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UNITED STATES SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549

Form 10-K(MARK ONE)

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF

1934FOR THE FISCAL YEAR ENDED DECEMBER 31, 2013

Or

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE

ACT OF 1934FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-7573

PARKER DRILLING COMPANY(Exact name of registrant as specified in its charter)

Delaware 73-0618660(State or other jurisdiction of

incorporation or organization) (I.R.S. Employer

Identification No.) 5 Greenway Plaza,

Suite 100, Houston, Texas 77046(Address of principal executive offices) (Zip code)

Registrant’s telephone number, including area code:(281) 406-2000

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Name of Each Exchange on Which Registered:Common Stock, par value $0.16 2/3 per share New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.Yes ¨ No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the ExchangeAct. Yes ¨ No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the SecuritiesExchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and(2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, everyInteractive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or forsuch shorter period that the registrant was required to submit and post such files). Yes þ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will notbe contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III ofthis Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smallerreporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of theExchange Act. (Check one):

Large accelerated filer ¨ Accelerated filer þ Non-accelerated filer ¨ Smaller reporting company ¨ (Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ¨ No þThe aggregate market value of our common stock held by non-affiliates on June 28, 2013 was $582.6 million. At March 3, 2014,

there were 120,557,208 shares of our common stock outstanding.

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DOCUMENTS INCORPORATED BY REFERENCEPortions of our definitive proxy statement for the Annual Meeting of Shareholders to be held on May 1, 2014 are incorporated by

reference in Part III.

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PagePART I

Item 1. Business 1Item 1A. Risk Factors 9Item 1B. Unresolved Staff Comments 19Item 2. Properties 19Item 3. Legal Proceedings 21Item 4. Mine Safety Disclosures 21

PART IIItem 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 22Item 6. Selected Financial Data 23Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 24Item 7A. Quantitative and Qualitative Disclosures about Market Risk 40Item 8. Financial Statements and Supplementary Data 42Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 85Item 9A. Controls and Procedures 85Item 9B. Other Information 86

PART IIIItem 10. Directors, Executive Officers and Corporate Governance 87Item 11. Executive Compensation

87Item 12. Security Ownership of Certain Beneficial Owners, Management and Related Stockholder Matters 87Item 13. Certain Relationships and Related Transactions, and Director Independence 87Item 14. Principal Accounting Fees and Services 87

PART IVItem 15. Exhibits and Financial Statement Schedules 88Signatures 94EX-21 EX-23.1 EX-31.1 EX-31.2 EX-32.1 EX-32.2

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PART IITEM 1. BUSINESSGeneral

Unless otherwise indicated, the terms “Company,” “Parker,” “we,” “us” and “our” refer to Parker Drilling Company together with itssubsidiaries and "Parker Drilling" refers solely to the parent, Parker Drilling Company. Parker Drilling was incorporated in the state ofOklahoma in 1954 after having been established in 1934. In March 1976, the state of incorporation of the Company was changed toDelaware. Our principal executive offices are located at 5 Greenway Plaza, Suite 100, Houston, Texas 77046.

We are an international provider of contract drilling and drilling-related services and rental tools. We have operated in over 50countries since beginning operations in 1934, making us among the most geographically experienced drilling contractors and rental toolsproviders in the world. We currently have operations in 24 countries, 10 of which we entered through our acquisition in 2013 ofInternational Tubular Services Limited and certain of its affiliates (collectively, ITS) and other related assets (the ITS Acquisition). Weown and operate drilling rigs and drilling-related equipment and also perform drilling-related services, referred to as Operations &Maintenance (O&M) work, for customer-owned drilling rigs on a contracted basis. We have extensive experience and expertise in drillinggeologically difficult wells and in managing the logistical and technological challenges of operating in remote, harsh and ecologicallysensitive areas. Our rental tools business supplies premium equipment to operators on land and offshore in the U.S. and select internationalmarkets. We have significant knowledge of the equipment needs of our customers and the logistical and product quality requirements of aneffective rental tools supplier. We believe we are industry leaders in quality, health, safety and environmental practices.

Our business is currently comprised of five operating segments: Rental Tools, U.S. Barge Drilling, U.S. Drilling, InternationalDrilling, and Technical Services.

Our Rental Tools BusinessOur rental tools business provides premium rental tools for land and offshore oil and natural gas drilling and workover and production

applications. Tools we provide include drill pipe, heavy-weight drill pipe, tubing, high-torque connections, blow-out preventers (BOPs),drill collars, casing running systems, tools for fishing services and more. Our U.S. rental tools business is headquartered in New Iberia,Louisiana and our international rental tools business is headquartered in Aberdeen, Scotland. We maintain an inventory of rental tools andprovide services to our customers from facilities in Louisiana, Texas, Oklahoma, Wyoming, North Dakota and West Virginia, as well as inthe Middle East, Latin America, the U.K. and Europe, and the Asia-Pacific regions.

During 2013, our largest single market for rental tools continued to be U.S. land drilling, a cyclical market driven primarily bycommodity prices and our customers' access to project financing. The increase in unconventional lateral drilling, often used in shaleformations, added to the market demand for rental tools, keeping our U.S. market focus in the regions of primary shale plays. A growingportion of our U.S. rental tools business is supplying tubular goods and other equipment to offshore Gulf of Mexico (GOM) customers.

On April 22, 2013, we completed the ITS Acquisition. ITS provides rental drilling equipment and pressure control systems, fishingservices, tubular running services and machine shop support for exploration and production (E&P) companies, drilling contractors andservice companies from 21 operating facilities. See Note 2, “Acquisition of ITS,” in Item 8 of this Form 10-K for further discussion.

Our principal customers are major and independent oil and natural gas E&P companies. Generally, rental tools are used for only aportion of a well drilling program and are requested by the customer when they are needed, requiring us to keep a broad inventory of rentaltools in stock. Rental tools are usually rented on a daily or monthly basis. For 2013, approximately 51.1 percent, 31.3 percent, and 17.6percent of revenues from our rental tools business were derived from U.S. land, international, and offshore GOM customers, respectively.

Our U.S. Barge Drilling BusinessOur U.S. GOM barge drilling rig fleet is the largest marketed barge fleet in the GOM region, with rigs ranging from 1,000 to 3,000

horsepower with drilling depth capabilities ranging from 13,000 to over 30,000 feet. Our rigs drill for oil and natural gas in the shallowwaters in and along the inland waterways and coasts of Louisiana, Alabama and Texas. The barge drilling industry in the GOM ischaracterized by cyclical activity where utilization and dayrates are typically driven by commodity prices and our customers’ access toproject financing. Contract terms tend to be well-to-well or multi-well programs, most commonly ranging from 45 to 150 days.

We continue to make investments in our barge drilling fleet to increase its efficiency and safety performance, and we expect to bringone additional rig to market in 2014. Our rigs are all equipped for zero-discharge operations and are suitable for

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a variety of drilling programs in inland coastal waters, from along inland waterways requiring shallow draft barges to open water drilling onthe continental shelf requiring more robust capabilities.

Our U.S. Drilling BusinessOur U.S. Drilling business primarily consists of two new-design arctic-class drilling rigs in Alaska intended to address the challenges

presented by the remote location, harsh climate and sensitive environment that characterize the Alaskan North Slope and O&M work insupport of ExxonMobil’s Santa Ynez Unit offshore platform operations located in the Channel Islands region of California. The arctic-classdrilling rigs deliver improved drilling efficiency, operating consistency and safety in this very demanding setting. In early December 2012we commenced drilling operations with the first rig. The second rig completed client acceptance testing and began drilling in February2013. The Alaskan North Slope drilling market is a focus of global and regional E&P companies with active programs to develop the area’shydrocarbon resources. In this market, drilling activity, and therefore production, is constrained by the existing limits of the infrastructure inplace and the capabilities of existing aged technology. We believe our new-design rigs contribute to expanded drilling capabilities for ourcustomers in this market.

Our International Drilling BusinessOur international drilling business includes operations related to Parker-owned and customer-owned rigs. We strive to deploy our

fleet of Parker-owned rigs in markets where we expect to have opportunities to keep the rigs at work consistently and build a sufficientpresence to achieve efficient operating scale. As of December 31, we had rigs operating in Mexico, Colombia, Kazakhstan, Papua NewGuinea, Indonesia, the Kurdistan Region of Iraq and Sakhalin Island, Russia. In addition, we have O&M and ongoing project managementactivities for customer-owned rigs in Sakhalin Island, Russia, Papua New Guinea, South Korea and Kuwait.

The international drilling markets in which we operate have one or more of the following characteristics:• customers that typically are major, independent or national oil and natural gas companies or integrated service

providers;• drilling programs in remote locations with little infrastructure requiring a large inventory of spare parts and other ancillary

equipment and self-supported service capabilities;• complex wells and/or harsh environments such as high pressure, deep depths, hazardous or geologically challenging conditions,

requiring specialized equipment and considerable experience to drill;• drilling contracts that generally cover periods of one year or more;

and• O&M contracts that are typically in support of multi-year drilling

programs.

Our Technical Services BusinessOur technical services business provides engineering and related project services during the Front End Engineering Design (FEED),

pre-FEED and concept development phases of customer-owned drilling facility projects. During the Engineering, Procurement,Construction and Installation (EPCI) phase, we focus primarily on the drilling systems engineering, procurement, commissioning andinstallation and we typically provide customer support during construction. Currently, we provide these services on the Berkut platformproject for Exxon Neftegas Limited (ENL). Additionally, we have a FEED engagement for an onshore arctic drilling facility project.Because these projects are customer-owned and customer-funded, the Technical Services business does not typically require significantcapital and we believe this business helps to position us for future expansion in the drilling O&M business.

Our technical services business is also our engineering expertise center and provides our ongoing businesses with services similar tothose provided to our external customers, including engineering design, retrofitting of existing rigs, modification, upgrades and othertechnology-related improvements.

Our StrategyWe intend to successfully compete in select energy services businesses which benefit our customers’ exploration, appraisal and

development programs, and in which operational execution is the key measure of success. We will do this by:• Consistently delivering innovative, reliable, and efficient results that help our customers reduce their operational risks and

manage their operating costs; and• Investing to improve and grow our existing business lines, and to expand the scope of products and services we

offer.

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Our Core CompetenciesThere are many factors that will affect our success, but key among them is strengthening our core competencies, which we believe are

the foundation for delivering operational excellence to our customers:Customer-aligned operational excellence: Our daily focus is meeting the needs of our customers. We strive to anticipate our

customers’ challenges and provide innovative, reliable and efficient solutions to help them achieve their business objectives.Rapid Personnel Development: Motivated, skilled and effective people are critical to the successful execution of our strategy. We

strive to attract and retain the best people, to develop depth and strength in key skills, and to provide a safety- and solutions-orientedworkforce to our customers.

Selective and Effective Market Entry: We are selective about the services we provide, geographies in which we operate, andcustomers we serve. We intend to build Parker’s business in markets with the best potential for sustained growth, profitability and operatingscale. We are strategic, timely and intentional when we enter new markets and when we grow organically or through acquisition orinvestments in new business ventures.

Enhanced Asset Management and Predictive Maintenance: We believe well-maintained rigs, equipment and rental tools are critical toproviding reliable results for our customers. We employ predictive and preventive maintenance programs and training to sustain high levelsof effective utilization and to provide reliable operating performance and efficiency.

Deployment of Standard, Modular and Configurable Processes and Equipment: To address the challenging and harsh environments inwhich our customers operate, we develop standardized processes and equipment that can be configured to meet each project’s distincttechnological requirements. Repeatable processes and modular equipment leverage our investments in assets and employees, increaseefficiency and reduce disruption.

We believe there are tangible rewards from delivering value to our customers through superior execution of our core competencies.When we deliver innovative, reliable and efficient solutions aligned with our customers’ needs, we believe we are well-positioned to earnpremium rates, generate follow-on business and create growth opportunities that enhance our financial performance and advance ourstrategy.

CustomersOur customer base consists of major, independent and national oil and natural gas companies and integrated service providers. Each

of our segments depends on a limited number of key customers and the loss of any one or more key customers could have a materialadverse effect on a segment. In 2013, our largest customer, Exxon Neftegas Limited (ENL) accounted for approximately 15.6 percent ofour total revenues.

CompetitionWe operate in highly competitive businesses characterized by high capital requirements, rigorous technological challenges, evolving

regulatory requirements and challenges in securing and retaining qualified field personnel.In the rental tools market we compete with suppliers both larger and smaller than our own business, some of which are components of

larger enterprises. Our rental tools business competes against other rental tools companies based on breadth of inventory, the availabilityand price of product and quality of service. In international land drilling markets, we compete with a number of international drillingcontractors as well as local contractors. Most contracts are awarded on a competitive bidding basis and operators often consider reliabilityand efficiency in addition to price. Although local drilling contractors typically have lower labor and mobilization costs, we are generallyable to distinguish ourselves from these companies based on our technical expertise, safety performance, quality of service, and experience.We believe our experience operating in challenging environments has been a significant factor in securing contracts and we believe themarket for drilling contracts will continue to be highly competitive with continued focus on safety, efficiency and quality.

In the GOM barge drilling market, we are awarded most contracts through a competitive bidding process. We have achieved somesuccess differentiating ourselves from competitors through our drilling performance, upgraded fleet, planned maintenance programs, well-trained and experienced crews and safety record. This strategy has resulted in safer and more efficient operations and we believe these areimportant factors in contract awards.

ContractsRental tools contracts are typically on a dayrate basis with rates determined based on type of equipment and competitive conditions.

Rental rates generally apply from the time the equipment leaves our facility until it is returned. Rental contracts generally require thecustomer to pay for lost, lost-in-hole or damaged equipment.

Most drilling contracts are awarded based on competitive bidding. The rates specified in drilling contracts vary depending upon thetype of rig employed, equipment and services supplied, geographic location, term of the contract,

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competitive conditions and other variables. Our contracts generally provide for an operating dayrate during drilling operations, with lowerrates for periods of equipment downtime, customer stoppage, adverse weather or other conditions, and no payment when certain conditionscontinue beyond contractually established parameters. When a rig mobilizes to or demobilizes from an operating area, the contract typicallyprovides for a different dayrate or specified fixed payments during mobilization or demobilization. The terms of most of our contracts arebased on either a specified period of time or the time required to drill a specified number of wells. The contract term in some instances maybe extended by the customer exercising options for an additional time period or for the drilling of additional wells, or by exercising a rightof first refusal. Most of our contracts allow termination by the customer prior to the end of the term without penalty under certaincircumstances, such as the loss of or major damage to the drilling unit or other events that cause the suspension of drilling operationsbeyond a specified period of time. Certain contracts require the customer to pay an early termination fee if the customer terminates acontract before the end of the term without cause, but in the remainder of the contracts the customer has the discretion to terminate thecontract without cause prior to the end of the term without penalty.

Technical Services contracts include engineering, consulting, and project management scopes of work and are typically on a time andmaterials basis.

SeasonalityOur rigs in the inland waters of the GOM are subject to severe weather during certain periods of the year, particularly during

hurricane season from June through November, which could halt operations for prolonged periods or limit contract opportunities duringthat period. In addition, mobilization, demobilization, or well-to-well movements of rigs in arctic regions can be affected by seasonalchanges in weather or weather so severe the conditions are deemed too unsafe to operate.

Insurance and IndemnificationOur operations are subject to hazards inherent in the drilling industry, such as blowouts, reservoir damage, loss of production, loss of

well control, lost or stuck drill strings, equipment defects, cratering, fires, explosions, pollution, and damage or loss during transportation.These hazards can cause personal injury or loss of life, severe damage to or destruction of property and equipment and pollution damage,which could lead to claims by third parties or customers, suspension of operations and contract terminations. Some of our fleet is alsosubject to hazards inherent in marine operations, either while on-site or during mobilization, such as capsizing, sinking, grounding,collision, damage from severe weather and marine life infestations.

Our contracts provide for varying levels of indemnification between ourselves and our customers, including with respect to wellcontrol and subsurface risks. We also maintain insurance for personal injuries, damage to or loss of equipment and other insurancecoverage for various business risks. Our insurance policies are typically 12-month policy periods.

Our insurance program provides coverage, to the extent not otherwise paid by the customer under the indemnification provisions ofthe drilling or rental tool contract, for liability due to well control events and liability arising from third-party claims, including wrongfuldeath and other personal injury claims by our personnel as well as claims brought on behalf of individuals who are not our employees.Generally, our program provides liability coverage up to $350.0 million, with retentions of $1.0 million or less.

Well control events generally include an unintended flow from the well that cannot be contained by using equipment on site (e.g., aBOP), by increasing the weight of drilling fluid or by diverting the fluids safely into production. Our insurance program provides coveragefor third-party liability claims relating to sudden and accidental pollution from a well control event up to $350.0 million per occurrence. Aseparate limit of $10.0 million exists to cover the costs of re-drilling of the well and well control costs under a Contingent Operators ExtraExpense policy. For our rig based operations, remediation plans are in place to prevent the spread of pollutants and our insurance programprovides coverage for removal, response and remedial actions. Our insurance program also provides coverage for liability resulting fromsudden and accidental pollution events originating from our rigs up to $350.0 million per occurrence. We retain the risk for liability notindemnified by the customer below the retention and in excess of our insurance coverage.

Based upon a Company risk assessment and due to the high cost, high self-insured retention and limited coverage insurance forwindstorms in the GOM, we have elected not to purchase windstorm insurance for our barge rigs in the GOM. Although we have retainedthe risk for physical loss or damage for these rigs arising from a named windstorm, we have procured insurance coverage for removal of awreck caused by a windstorm.

Our contracts provide for varying levels of indemnification from our customers and may require us to indemnify our customers.Liability with respect to personnel and property is customarily assigned on a “knock-for-knock” basis, which means that we and ourcustomers customarily assume liability for our respective personnel and property regardless of fault. In addition, our customers typicallyindemnify us for damage to our equipment down-hole, and in some cases our subsea equipment, generally based on replacement cost minussome level of depreciation. However, in certain contracts we may assume liability for damage to our customer’s property and other third-party property on the rig and in other contracts we are

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not indemnified by our customers for damage to their property and, accordingly, could be liable for any such damage under applicable law.Our customers typically assume responsibility for and indemnify us from any loss or liability resulting from pollution, including

clean-up and removal and third-party damages, arising from operations under the contract and originating below the surface of the land orwater, including as a result of blowouts or cratering of the well. In some contracts, however, we may have liability for damages resultingfrom such pollution or contamination caused by our gross negligence, or in some cases, ordinary negligence.

We generally indemnify the customer for legal and financial consequences of spills of industrial waste, lubricants, solvents and othercontaminants (other than drilling fluid) on the surface of the land or water originating from our rigs or equipment. We typically require ourcustomers to retain liability for spills of drilling fluid (sometimes called “mud”) which circulates down-hole to the drill bit, lubricates thebit and washes debris back to the surface. Drilling fluid often contains a mixture of synthetics, the exact composition of which is prescribedby the customer based on the particular geology of the well being drilled.

The above description of our insurance program and the indemnification provisions typically found in our contracts is only asummary as of the date hereof and is general in nature. Our insurance program and the terms of our drilling and rental tool contracts maychange in the future. In addition, the indemnification provisions of our contracts may be subject to differing interpretations, andenforcement of those provisions may be limited by public policy and other considerations.

If any of the aforementioned operating hazards results in substantial liability and our insurance and contractual indemnificationprovisions are unavailable or insufficient, our financial condition, operating results or cash flows may be materially adversely affected.

EmployeesThe following table sets forth the composition of our employee base:

December 31,

2013 2012Rental Tools 1,122 279U.S. Barge Drilling 444 387U.S. Drilling 278 144International Drilling 1,291 1,019Technical Services and Corporate 260 256

Total employees 3,395 2,085

Environmental ConsiderationsOur operations are subject to numerous U.S. federal, state, local and foreign laws and regulations governing the discharge of materials

into the environment or otherwise relating to environmental protection. Numerous foreign and U.S. governmental agencies, such as theU.S. Environmental Protection Agency (EPA), issue regulations to implement and enforce such laws, which often require difficult andcostly compliance measures that carry substantial administrative, civil and criminal penalties or may result in injunctive relief for failure tocomply. These laws and regulations may require the acquisition of a permit before drilling commences; restrict the types, quantities andconcentrations of various substances that can be released into the environment in connection with drilling and production activities; limit orprohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protectedareas; require remedial action to clean up pollution from former operations; and impose substantial liabilities for pollution resulting fromour operations. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costlycompliance could adversely affect our operations and financial position, as well as those of similarly situated entities operating in the samemarkets. While our management believes that we comply with current applicable environmental laws and regulations, there is no assurancethat compliance can be maintained in the future.

As an owner or operator of both onshore and offshore facilities, including mobile offshore drilling rigs in or near waters of the UnitedStates, we may be liable for the costs of clean up and damages arising out of a pollution incident to the extent set forth in the Federal WaterPollution Control Act (commonly known as the Clean Water Act (CWA), as amended by the Oil Pollution Act of 1990 (OPA); the CleanAir Act (CAA); the Outer Continental Shelf Lands Act (OCSLA); the Comprehensive Environmental Response, Compensation andLiability Act (CERCLA); the Resource Conservation and Recovery Act (RCRA); Emergency Planning and Community Right to Know Act(EPCRA); Hazardous Materials Transportation Act (HMTA) and comparable state laws, each as may be amended from time to time. Inaddition, we may also be subject to applicable state law and other civil claims arising out of any such incident.

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The OPA and regulations promulgated pursuant thereto impose a variety of regulations on “responsible parties” related to theprevention of spills of oil or other hazardous substances and liability for damages resulting from such spills. “Responsible parties” includethe owner or operator of a vessel, pipeline or onshore facility, or the lessee or permittee of the area in which an offshore facility is located.The OPA assigns liability of oil removal costs and a variety of public and private damages to each responsible party.

The OPA liability for a mobile offshore drilling rig is determined by whether the unit is functioning as a vessel or is in place andfunctioning as an offshore facility. If operating as a vessel, liability limits of $1,000 per gross ton or $854,400, whichever is greater, apply.If functioning as an offshore facility, the mobile offshore drilling rig is considered a “tank vessel” for spills of oil or hazardous substanceson or above the water surface, with liability limits of $3,200 per gross ton or $23.5 million, whichever is greater. To the extent damages andremoval costs exceed this amount, the mobile offshore drilling rig will be treated as an offshore facility and the offshore lessee will beresponsible up to higher liability limits for all removal costs plus $75.0 million. The party must reimburse all removal costs actuallyincurred by a governmental entity for actual or threatened oil or hazardous substance discharges associated with any Outer ContinentalShelf facilities, without regard to the limits described above. A party also cannot take advantage of liability limits if the spill was caused bygross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation. If the party failsto report a spill or to cooperate fully in the cleanup, liability limits likewise do not apply.

Few defenses exist to the liability imposed by the OPA. The OPA also imposes ongoing requirements on a responsible party,including proof of financial responsibility, for offshore facilities and vessels in excess of 300 gross tons (to cover at least some costs in apotential spill) and preparation of an oil spill contingency plan for offshore facilities and vessels. The OPA requires owners and operatorsof offshore facilities that have a worst case oil or hazardous substance spill potential of more than 1,000 barrels to demonstrate financialresponsibility in amounts ranging from $10.0 million in specified state waters to $35.0 million in federal Outer Continental Shelf waters,with higher amounts, up to $150.0 million, in certain limited circumstances where the Bureau of Ocean Energy Management (BOEM)believes such a level is justified by the risks posed by the quantity or quality of oil or hazardous substance that is handled by the facility.For “tank vessels,” as our offshore drilling rigs are typically classified, the OPA requires owners and operators to demonstrate financialresponsibility in the amount of their largest vessel’s liability limit, as those limits are described in the preceding paragraph. Failure tocomply with ongoing requirements or inadequate cooperation in a spill may subject a responsible party to civil or criminal enforcementactions.

The OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating onthe Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms,vehicles and structures. The Bureau of Safety and Environmental Enforcement (“BSEE”) regulates the design and operation of well controland other equipment at offshore production sites, implementation of safety and environmental management systems, and mandatory third-party compliance audits, among other requirements. BSEE has proposed stricter requirements for subsea drilling production equipment andhas indicated that there will be an additional, separate rulemaking to govern the design, performance and maintenance of BOPs, but thatrule has not yet been published. BSEE has also published a draft statement of policy on safety culture with nine proposed characteristics ofa robust safety culture. Finally, together with BOEM, BSEE is drafting new standards governing drilling in the Arctic. BSEE contends thatit has the legal authority to extend its regulatory reach to include contractors, like us, in addition to operators. Violations of environmentallyrelated lease conditions or regulations issued pursuant to the OCSLA can result in substantial civil and criminal penalties as well aspotential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities, delay or restriction of activitiescan result from either governmental or citizen prosecution.

Our operating U.S. barge drilling rigs are designed to achieve zero-discharge as required by laws, such as the CWA. In addition, inrecognition of environmental concerns regarding dredging of inland waters and permitting requirements, we conduct negligible dredgingoperations, with approximately two-thirds of our offshore drilling contracts involving directional drilling, which minimizes the need fordredging. However, the existence of such laws and regulations (e.g., Section 404 of the CWA, Section 10 of the Rivers and Harbors Act,etc.) has had and will continue to have a restrictive effect on us and our customers.

Our operations are also governed by laws and regulations related to workplace safety and worker health, primarily the OccupationalSafety and Health Act and regulations promulgated thereunder. In addition, various other governmental and quasi-governmental agenciesrequire us to obtain certain miscellaneous permits, licenses and certificates with respect to our operations. The kind of permits, licenses andcertificates required by our operations depend upon a number of factors. We believe we have the necessary permits, licenses andcertificates that are material to the conduct of our existing business.

CERCLA (also known as “Superfund”) and comparable state laws impose liability without regard to fault or the legality of theoriginal conduct, on certain classes of persons who are considered to be responsible for the release of a “hazardous substance” into theenvironment. While CERCLA exempts crude oil from the definition of hazardous substances for purposes of the statute, our operationsmay involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to abroad class of potentially responsible parties for all response and remediation costs, as well

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as natural resource damages. In addition, persons responsible for release of hazardous substances under CERCLA may be subject to jointand several liability for the cost of cleaning up the hazardous substances released into the environment and for damages to naturalresources. Few defenses exist to the liability imposed by CERCLA.

RCRA and comparable state laws regulate the management of wastes. Current RCRA regulations specifically excludes from thedefinition of hazardous waste “drilling fluids, produced waters, and other wastes associated with the exploration, development orproduction of crude oil, natural gas or geothermal energy.” However, these wastes may be regulated by EPA or state agencies as solidwaste. Moreover, ordinary industrial wastes, such as paint wastes, spent solvents, laboratory wastes, and used oils, may be regulated ashazardous waste. Although the costs of managing solid and hazardous wastes may be significant, we do not expect to experience moreburdensome costs than similarly situated companies involved in drilling operations in the Gulf Coast market.

The CAA, comparable state laws, and implementing regulations restrict the emission of air pollutants from various sources, and mayrequire us to obtain permits for the construction, modification, or operation of certain projects or facilities and utilize specific equipment ortechnologies to control emissions. For example, the EPA has adopted regulations known as “RICE MACT” that require the use of“maximum achievable control technology” to reduce formaldehyde and other emissions from certain stationary reciprocating internalcombustion engines, which can include portable engines used to power drilling rigs.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs) andwhich include carbon dioxide and methane, may be contributing to the warming of the atmosphere resulting in climate change. In responseto such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, are attractingincreasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climatechange are in various phases of discussions or implementation at international, national, regional and state levels.

In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding setof emission targets for GHGs, became binding on all those countries that had ratified it. International discussions are currently underway todevelop a treaty to replace the Kyoto Protocol after its expiration in 2020. In the United States, federal legislation imposing restrictions onGHGs is under consideration. Proposed legislation has been introduced that would establish an economy-wide cap on emissions of GHGsand would require most sources of GHG emissions to obtain GHG emission “allowances” corresponding to their annual emissions.Legislation has also been considered that would establish taxes tied to GHG emissions. In addition, the EPA is taking steps to regulateGHGs as pollutants under the CAA. To-date, the EPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, whichestablishes a new comprehensive scheme requiring operators of stationary sources (including certain oil and natural gas productionsystems) in the United States emitting more than established annual thresholds of carbon dioxide-equivalent GHGs to inventory and reporttheir GHG emissions annually; (ii) an “Endangerment Finding” final rule, effective January 14, 2010 which states that current andprojected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines,threaten public health and welfare, which allowed the EPA to finalize motor vehicle GHG standards (the effect of which could reducedemand for motor fuels refined from crude oil); and (iii) a final rule, effective August 2, 2010, to address permitting of GHG emissionsfrom stationary sources under the CAA’s Prevention of Significant Deterioration (PSD) and Title V programs. This final rule “tailors” thePSD and Title V programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources firstsubject to permitting.

Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treatiesor international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources,could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demandfor oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties orinternational agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impacton our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation orregulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. Anincrease in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and result in adisruption of our customers’ operations.

FINANCIAL INFORMATION ABOUT INDUSTRY SEGMENTS AND GEOGRAPHIC AREASWe have five operating segments: Rental Tools, U.S. Barge Drilling, U.S. Drilling, International Drilling, and Technical Services.

Historically we reported a sixth segment, Construction Contract, for which there was no activity during the nine months ended September30, 2013 or the year ended December 31, 2012. As a result of the reversal of reserves relating to this segment in the fourth quarter of 2013,this segment has been included in this report. See Item 7. Information about our reportable segments and operations by geographic areas forthe years ended December 31, 2013, 2012 and 2011 is set forth in Note 14 included in Item 8 of this report.

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EXECUTIVE OFFICERSOfficers are elected each year by the board of directors following the annual shareholders' meeting for a term of one year or until the

election and qualification of their successors. The current executive officers of the Company and their ages, positions with the Companyand business experience are presented below:

• Gary G. Rich, 55, joined the Company in October 2012 as the president and chief executive officer. Mr. Rich also serves as amember of the Company’s board of directors. He is an industry veteran with over 30 years of global technical, commercial andoperations experience. Mr. Rich came to Parker Drilling after a 25-year career with Baker Hughes Incorporated. Mr. Rich servedas vice president of global sales for Baker Hughes from August 2011 to October 2012, and prior to that role, he served aspresident of that company’s European operations from April 2009 to August 2011. Previously, Mr. Rich was president of HughesChristensen Company (HCC), a division of Baker Hughes primarily focused on the production and distribution of drilling bits forthe petroleum industry.

• Christopher T. Weber, 41 joined the Company in May 2013 as the senior vice president and chief financial officer. Prior tojoining the Company, Mr. Weber served as the vice president and treasurer of Ensco plc., a public offshore drilling company,from 2011 to May 2013. From 2009 to 2011, Mr. Weber served as vice president, operations for Pride International, Inc., prior towhich he served as director, corporate planning and development from 2006 to 2009.

• Jon-Al Duplantier, 46, is the senior vice president, chief administrative officer, general counsel, and secretary of the Company, aposition held since 2013. Mr. Duplantier has over 18 years experience in the oil and gas industry. Mr. Duplantier joined theCompany in 2009 as vice president and general counsel. From 1995 to 2009, Mr. Duplantier served in several legal and businessroles at ConocoPhillips, including senior counsel – Exploration and Production, vice president and general counsel – ConocoPhillips Indonesia, and vice president and general counsel – Dubai Petroleum Company. Prior to joining ConocoPhillips, heserved as a patent attorney for DuPont from 1992 to 1995.

• David R. Farmer, 52, was appointed the senior vice president, Europe, Middle East, and Asia (EMEA) in early 2014. He joinedthe Company in 2011 as vice president of operations. Mr. Farmer has over 20 years' experience in the upstream oilfield servicesbusiness working in executive, engineering, operational, marketing, account management, planning, and general managementroles in Europe, the Middle East, North America and South America. From 1991 to 2011, Mr. Farmer served in various positionsat Schlumberger, including vice president and global account director – Schlumberger Ltd. The Netherlands, vice president andgeneral manager – Schlumberger Oilfield Service Qatar, global marketing manager – Schlumberger Drilling & MeasurementDivision, Houston, Texas. Most recently, Mr. Farmer was responsible for Demand Planning management and the development oflong term tactical resource plans for Schlumberger’s Drilling & Measurement division.

• Philip L. Agnew, 45, has served as the Company's senior vice president and chief technical officer since 2013. He joined theCompany in December 2010 as vice president of technical services. Mr. Agnew has more than 20 years' experience in design,construction and project management. From 2003 to 2010, Mr. Agnew held the position of President at Aker MH, Inc., a businessunit of Aker Solutions AS. From 1998 to 2003, Mr. Agnew served as Project Manager and then vice president – ProjectDevelopment at Signal International (previously Friede Goldman Offshore; TDI-Halter LP; Texas Drydock, Inc.). Prior to hiscareer at Signal International, Mr. Agnew served a variety of leadership roles at Schlumberger Sedco Forex InternationalResources, Interface Consulting International, Inc., and Brown & Root, Inc.

Other Parker Drilling Company Officers

• J. Daniel Chapman, 43, joined the Company in 2009 as chief compliance officer and counsel. Prior to joining the Company,Mr. Chapman was employed by Baker Hughes from 2002 to 2009 where he served in several legal counsel positions includingcompliance counsel, international trade counsel, division counsel (drilling fluids), and global ethics and compliance director.Prior to 2002, Mr. Chapman was employed as a securities and mergers and acquisitions lawyer with the law firms Freshfields(London) and King & Spalding (Atlanta and Houston).

• Philip A. Schlom, 49, joined the Company in 2009 as principal accounting officer and corporate controller. From 2008 to 2009, heheld the position of vice president and corporate controller for Shared Technologies Inc. From 1997 to 2008, Mr. Schlom heldseveral senior financial positions at Flowserve Corporation, a leading manufacturer of pumps, valves and seals for the energysector. From 1988 through 1997, Mr. Schlom worked at the public accounting firm PricewaterhouseCoopers.

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• David W. Tucker, 58, treasurer, joined the Company in 1978 as a financial analyst and served in various financial and accountingpositions before being named chief financial officer of our formerly wholly-owned subsidiary, Hercules Offshore Corporation, inFebruary 1998. Mr. Tucker was named treasurer of the Company in 1999.

Available InformationWe make available free of charge on our website at www.parkerdrilling.com our annual reports on Form 10-K, quarterly reports on

Form 10-Q, current reports on Form 8-K and amendments to those reports as soon as reasonably practicable after we electronically filesuch material with, or furnish such material to, the Securities and Exchange Commission (SEC). Additionally, these reports are available onan Internet website maintained by the SEC at www.sec.gov.

ITEM 1A. RISKFACTORS

Our businesses involve a high degree of risk. You should consider carefully the risks and uncertainties described below and the otherinformation included in this Form 10-K, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operationsand Item 8, Financial Statements and Supplementary Data. While these are the risks and uncertainties we believe are most important foryou to consider, you should know that they are not the only risks or uncertainties facing us or which may adversely affect our business. Ifany of the following risks or uncertainties actually occurs, our business, financial condition or results of operations could be adverselyaffected.

Volatile oil and natural gas prices impact demand for our services. A decrease in demand for crude oil and natural gas or otherfactors may reduce demand for our services and substantially reduce our profitability or result in losses.

The success of our operations is significantly dependent upon the exploration and development activities of the major, independentand national oil and natural gas companies and large integrated service companies that comprise our customer base. Oil and natural gasprices and market expectations regarding potential changes in these prices can be extremely volatile. Increases or decreases in oil andnatural gas prices and expectations of future prices could have an impact on our customers’ long-term exploration and developmentactivities, which in turn could materially affect our business and financial performance. Higher commodity prices do not necessarily resultimmediately in increased drilling activity because our customers’ expectations of future commodity prices typically drive demand for ourdrilling services.

Commodity prices and demand for our services also depends upon numerous factors which are beyond our control, including:• the demand for oil and natural

gas;• the cost of exploring for, producing and delivering oil and natural

gas;• expectations regarding future energy

prices;• advances in exploration, development and production

technology;• the adoption or repeal of laws and government regulations, both in the United States and other

countries;• the imposition or lifting of economic sanctions against certain regions, persons and other

entities;• the number of ongoing and recently completed rig construction projects which may create

overcapacity;• local and worldwide military, political and economic events, including events in the oil producing countries of Africa, the Middle

East, Russia, Central Asia, Southeast Asia and Latin America;• the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain production levels and

prices;• the level of production by non-OPEC

countries;• weather

conditions;• expansion or contraction of worldwide economic activity, which affects levels of consumer and industrial

demand;• the rate of discovery of new oil and natural gas

reserves;• domestic and foreign tax

policies;• acts of terrorism in the United States or

elsewhere;• the development and use of alternative energy

sources; and• the policies of various governments regarding exploration and development of their oil and natural gas

reserves.

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A slowdown in economic activity may result in lower demand for our drilling and drilling related services and rental tools business,and could have a material adverse effect on our business.

A slowdown in economic activity in the United States or abroad, could lead to uncertainty in corporate credit availability and capitalmarket access and could reduce worldwide demand for energy and result in lower crude oil and natural gas prices. Our business depends toa significant extent on the level of international onshore drilling activity and GOM inland and offshore drilling activity for oil and naturalgas. Depressed oil and natural gas prices from lower demand as a result of slow or negative economic growth would reduce the level ofexploration, development and production activity, all of which could cause our revenues and margins to decline, decrease dayrates andutilization of our rigs and use of our rental tools and limit our future growth prospects. Any significant decrease in dayrates or utilization ofour rigs or use of our rental tools could materially reduce our revenue and profitability. In addition, current and potential customers whodepend on financing for their drilling projects may be forced to curtail or delay projects and may also experience an inability to paysuppliers and service providers, including us. Likewise, economic conditions in the United States or abroad could impact our vendors’ andsuppliers’ ability to meet obligations to provide materials and services in general. All of these factors could have a material adverse effecton our business and financial results.

Rig upgrade, refurbishment and construction projects are subject to risks and uncertainties, including delays and cost overruns,which could have an adverse impact on our results of operations and cash flows.

We regularly make significant expenditures in connection with upgrading and refurbishing our rig fleet. These activities includeplanned upgrades to maintain quality standards, routine maintenance and repairs, changes made at the request of customers, and changesmade to comply with environmental or other regulations. Rig upgrade, refurbishment and construction projects are subject to the risks ofdelay or cost overruns inherent in any large construction project, including the following:

• shortages of equipment or skilledlabor;

• unforeseen engineeringproblems;

• unanticipated changeorders;

• workstoppages;

• adverse weatherconditions;

• unexpectedly long delivery times for manufactured rigcomponents;

• unanticipated repairs to correct defects in construction not covered bywarranty;

• failure or delay of third-party equipment vendors or serviceproviders;

• unforeseen increases in the cost of equipment, labor or raw materials, particularlysteel;

• disputes with customers, shipyards orsuppliers;

• latent damages or deterioration to hull, equipment and machinery in excess of engineering estimates andassumptions;

• financial or other difficulties with current customers at shipyards andsuppliers;

• loss of revenue associated with downtime to remedy malfunctioning equipment not covered bywarranty;

• unanticipated costincreases;

• loss of revenue and payments of liquidated damages for downtime to perform repairs associated with defects, unanticipatedequipment refurbishment and delays in commencement of operations; and

• lack of ability to obtain the required permits or approvals, including import/exportdocumentation.

Any one of the above risks could adversely affect our financial condition and results of operations. Delays in the delivery of rigsbeing constructed or undergoing upgrade, refurbishment or repair may, in many cases, delay commencement of a drilling contract resultingin a loss of revenue to us, and may also cause our customer to renegotiate the drilling contract for the rig or terminate or shorten the term ofthe contract under applicable late delivery clauses, if any. If one of these contracts is terminated, we may not be able to secure areplacement contract on as favorable terms, if at all. Additionally, actual expenditures for required upgrades or to refurbish or construct rigscould exceed our planned capital expenditures, impairing our ability to service our debt obligations.

Failure to attract and retain skilled and experienced personnel could affect our operations.We require skilled, trained and experienced personnel to provide our customers with the highest quality technical services and

support for our drilling operations. We compete with other oilfield services businesses and other employers to attract and retain qualifiedpersonnel with the technical skills and experience we require. Competition for skilled labor and other labor

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required for our operations intensifies as the number of rigs activated or added to worldwide fleets or under construction increases, creatingupward pressure on wages. In periods of high utilization, we have found it more difficult to find and retain qualified individuals. A shortagein the available labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations couldmake it more difficult for us to attract and retain personnel and could require us to enhance our wage and benefits packages. Increases inour operating costs could adversely affect our business and financial results. Moreover, the shortages of qualified personnel or the inabilityto obtain and retain qualified personnel could negatively affect the quality, safety and timeliness of our operations.

Our debt levels and debt agreement restrictions may limit our liquidity and flexibility in obtaining additional financing and inpursuing other business opportunities.

As of December 31, 2013, we had:• $653.8 million of long-term debt, including $25.0 million of current portion of long-term

debt;• $52.1 million of operating lease

commitments; and• $4.6 million of standby letters of

credit.Our ability to meet our debt service obligations depends on our ability to generate positive cash flows from operations. We have in

the past, and may in the future, incur negative cash flows from one or more segments of our operating activities. Our future cash flowsfrom operating activities will be influenced by the demand for our drilling services, the utilization of our rigs, the dayrates that we receivefor our rigs, demand for our rental tools, general economic conditions and financial, business and other factors affecting our operations,many of which are beyond our control.

If we are unable to service our debt obligations, we may have to take one or more of the following actions:• delay spending on capital projects, including maintenance projects and the acquisition or construction of additional rigs, rental

tools and other assets;• sell equity or

assets; and• restructure or refinance our

debt.Additional indebtedness or equity financing may not be available to us in the future for the refinancing or repayment of existing

indebtedness, or if available, such additional indebtedness or equity financing may not be available on a timely basis, or on termsacceptable to us and within the limitations specified in our then existing debt instruments. In addition, in the event we decide to sell assets,we can provide no assurance as to the timing of any asset sales or the proceeds that could be realized from any such asset sale. Our abilityto generate sufficient cash flow from operating activities to pay the principal of and interest on our indebtedness is subject to certain marketconditions and other factors which are beyond our control.

Increases in the level of our debt and restrictions in the covenants contained in the instruments governing our debt could haveimportant consequences to you. For example, they could:

• result in a reduction of our credit rating, which would make it more difficult for us to obtain additional financing on acceptableterms;

• require us to dedicate a substantial portion of our cash flows from operating activities to the repayment of our debt and theinterest associated with our debt;

• limit our operating flexibility due to financial and other restrictive covenants, including restrictions on incurring additional debt,and create liens on our properties;

• place us at a competitive disadvantage compared with our competitors that have relatively lessdebt; and

• make us more vulnerable to downturns in ourbusiness.

Our current operations and future growth may require significant additional capital, and the amount of our indebtedness couldimpair our ability to fund our capital requirements.

Our business requires substantial capital. Currently, we anticipate that our capital expenditures in 2014 will be between $180 millionand $200 million. We may require additional capital in the event of growth opportunities, unanticipated maintenance requirements orsignificant departures from our current business plan.

Additional financing may not be available on a timely basis or on terms acceptable to us and within the limitations contained in ourAmended and Restated Senior Secured Credit Agreement (Secured Credit Agreement) and the indentures governing our outstanding9.125% Senior Notes due 2018 (9.125% Notes), 7.50% Senior Notes due 2020 (7.50% Notes) and 6.75% Senior Notes due 2022 (6.75%Notes, and collectively with the 9.125% Notes and the 7.50% Notes, Senior Notes). Failure to obtain additional financing, should the needfor it develop, could impair our ability to fund capital expenditure requirements and meet debt service requirements and could have anadverse effect on our business.

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Our Secured Credit Agreement and the indentures for our Senior Notes impose significant operating and financial restrictions, whichmay prevent us from capitalizing on business opportunities and taking some actions.

The Secured Credit Agreement and the indentures governing our senior notes impose significant operating and financial restrictionson us. These restrictions limit our ability to:

• make investments and other restricted payments, includingdividends;

• incur additionalindebtedness;

• createliens;

• engage in sale leasebacktransactions;

• sell our assets or consolidate or merge with or into othercompanies; and

• engage in transactions withaffiliates.

These limitations are subject to a number of important qualifications and exceptions. Our Secured Credit Agreement also requires usto maintain ratios for consolidated leverage, consolidated interest coverage and consolidated senior secured leverage. These covenants mayadversely affect our ability to finance our future operations and capital needs and to pursue available business opportunities. A breach ofany of these covenants could result in a default with respect to the related indebtedness. If a default were to occur, the lenders under ourSecured Credit Agreement and the holders of our Senior Notes could elect to declare the indebtedness, together with accrued interest,immediately due and payable. If the repayment of the indebtedness were to be accelerated after any applicable notice or grace periods, wemay not have sufficient funds to repay the indebtedness.

Certain of our contracts are subject to cancellation by our customers without penalty and with little or no notice.Certain of our contracts are subject to cancellation by our customers without penalty and with relatively little or no notice. When

drilling market conditions are depressed, a customer may no longer need a rig or rental tools that is currently under contract or may be ableto obtain comparable equipment at lower dayrates. Further, due to government actions, a customer may no longer be able to operate in, or itmay not be economical to operate in, certain regions. As a result, customers may leverage their termination rights in an effort to renegotiatecontract terms.

Our customers may also seek to terminate contracts if we experience operational problems. If our equipment fails to function properlyand cannot be repaired promptly, our customers will not be able to engage in drilling operations and may have the right to terminate thecontracts. If equipment is not timely delivered to a customer or does not pass acceptance testing, a customer may in certain circumstanceshave the right to terminate the contract. Even the payment of a termination fee may not fully compensate us for the loss of the contract.Early termination of a contract may result in a rig or other equipment being idle for an extended period of time. The likelihood that acustomer may seek to terminate a contract is increased during periods of market weakness. The cancellation or renegotiation of a number ofour contracts could materially reduce our revenue and profitability.

We rely on a small number of customers and the loss of a significant customer could adversely affect us.A substantial percentage of our revenues are generated from a relatively small number of customers and the loss of a significant

customer could adversely affect us. In 2013, our largest customer, Exxon Neftegas Limited accounted for approximately 15.6 percent ofour total revenues. Each of our segments depends on a limited number of key customers and the loss of any one or more key customerscould have a material adverse effect on a segment. Our consolidated results of operations could be adversely affected if any of oursignificant customers terminate their contracts with us, fail to renew our existing contracts or refuse to award new contracts to us.

The contract drilling and the rental tools businesses are highly competitive and cyclical, with intense price competition.The contract drilling and rental tools markets are highly competitive and many of our competitors in both the contract drilling and

rental tools businesses may possess greater financial resources than we do. Some of our competitors also are incorporated in countries thatmay provide them with significant tax advantages that are not available to us as a U.S. company and which may impair our ability tocompete with them for many projects.

Contract drilling companies compete primarily on a regional basis, and competition may vary significantly from region to region atany particular time. Many drilling and workover rigs can be moved from one region to another in response to changes in levels of activity,provided market conditions warrant, which may result in an oversupply of rigs in an area. Many competitors have constructed numerousrigs during periods of high energy prices and, consequently, the number of rigs available in some of the markets in which we operate hasexceeded the demand for rigs for extended periods of time, resulting in intense price competition. Most drilling contracts are awarded onthe basis of competitive bids, which also results in price competition. Historically, the drilling service industry has been highly cyclical,with periods of high demand, limited equipment

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supply and high dayrates often followed by periods of low demand, excess equipment supply and low dayrates. Periods of low demand andexcess equipment supply intensify the competition in the industry and often result in equipment being idle for long periods of time. Duringperiods of decreased demand we typically experience significant reductions in dayrates and utilization. The Company, or its competition,may move rigs or other equipment from one geographic location to another location; the cost of which may be substantial. If we experiencereductions in dayrates or if we cannot keep our equipment utilized, our financial performance will be adversely impacted. Prolongedperiods of low utilization and dayrates could result in the recognition of impairment charges on certain of our rigs if future cash flowestimates, based upon information available to management at the time, indicate that the carrying value of these rigs may not berecoverable.

Our international operations are subject to governmental regulation and other risks.We derive a significant portion of our revenues from our international operations. In 2013, we derived approximately 48.1 percent of

our revenues from operations in countries outside the United States. Our international operations are subject to the following risks, amongothers:

• political, social and economic instability, war, terrorism and civildisturbances;

• limitations on insurance coverage, such as war risk coverage, in certainareas;

• expropriation, confiscatory taxation and nationalization of ourassets;

• foreign laws and governmental regulation, including inconsistencies and unexpected changes in laws or regulatory requirements,and changes in interpretations or enforcement of existing laws or regulations;

• increases in governmentalroyalties;

• import-export quotas or tradebarriers;

• hiring and retaining skilled and experienced workers, some of whom are represented by foreign laborunions;

• workstoppages;

• damage to our equipment or violence directed at our employees, includingkidnapping;

• piracy of vessels transporting our people orequipment;

• unfavorable changes in foreign monetary and taxpolicies;

• solicitation by government officials for improper payments or other forms ofcorruption;

• foreign currency fluctuations and restrictions on currencyrepatriation;

• repudiation, nullification, modification or renegotiation ofcontracts; and

• other forms of governmental regulation and economic conditions that are beyond ourcontrol.

We currently have operations in 24 countries. Our operations are subject to interruption, suspension and possible expropriation due toterrorism, war, civil disturbances, political and capital instability and similar events, and we have previously suffered loss of revenue anddamage to equipment due to political violence. Civil and political disturbances in international locations may affect our operations. We maynot be able to obtain insurance policies covering risks associated with these types of events, especially political violence coverage, and suchpolicies may only be available with premiums that are not commercially justifiable.

Our international operations are subject to the laws and regulations of a number of foreign countries with political, regulatory andjudicial systems and regimes that may differ significantly from those in the United States. Our ability to compete in international contractdrilling and rental tool markets may be adversely affected by foreign governmental regulations and/or policies that favor the awarding ofcontracts to contractors in which nationals of those foreign countries have substantial ownership interests or by regulations requiring foreigncontractors to employ citizens of, or purchase supplies from, a particular jurisdiction. Furthermore, our foreign subsidiaries may facegovernmentally imposed restrictions or fees from time to time on the transfer of funds to us.

In addition, tax and other laws and regulations in some foreign countries are not always interpreted consistently among local, regionaland national authorities, which can result in disputes between us and governing authorities. The ultimate outcome of these disputes is nevercertain, and it is possible that the outcomes could have an adverse effect on our financial performance.

A portion of the workers we employ in our international operations are members of labor unions or otherwise subject to collectivebargaining. We may not be able to hire and retain a sufficient number of skilled and experienced workers for wages and other benefits thatwe believe are commercially reasonable.

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We may experience currency exchange losses where revenues are received or expenses are paid in nonconvertible currencies orwhere we do not take protective measures against exposure to a foreign currency. We may also incur losses as a result of an inability tocollect revenues because of a shortage of convertible currency available to the country of operation, controls over currency exchange orcontrols over the repatriation of income or capital. Given the international scope of our operations, we are exposed to risks of currencyfluctuation and restrictions on currency repatriation. We attempt to limit the risks of currency fluctuation and restrictions on currencyrepatriation where possible by obtaining contracts payable in U.S. dollars or freely convertible foreign currency. In addition, some partieswith which we do business could require that all or a portion of our revenues be paid in local currencies. Foreign currency fluctuations,therefore, could have a material adverse effect upon our results of operations and financial condition.

The shipment of goods, services and technology across international borders subjects us to extensive trade laws and regulations. Ourimport activities are governed by the unique customs laws and regulations in each of the countries where we operate. Moreover, manycountries, including the U.S., control the export and re-export of certain goods, services and technology and impose related exportrecordkeeping and reporting obligations. Governments may also impose economic sanctions against certain countries, persons and otherentities that may restrict or prohibit transactions involving such countries, persons and entities. The laws and regulations concerning importactivity, export recordkeeping and reporting, export control and economic sanctions are complex and constantly changing. These laws andregulations can cause delays in shipments and unscheduled operational downtime. Moreover, any failure to comply with applicable legaland regulatory trading obligations could result in criminal and civil penalties and sanctions, such as fines, imprisonment, debarment fromgovernmental contracts, seizure of shipments and loss of import and export privileges.

Failure to comply with anti-corruption laws, such as the U.S. Foreign Corrupt Practices Act and the U.K. Bribery Act 2010, couldresult in fines, criminal penalties, negative commercial consequences and an adverse effect on our business.

The U.S. Foreign Corrupt Practices Act (FCPA), the U.K. Bribery Act 2010 and similar anti-corruption laws in other jurisdictionsgenerally prohibit companies and their intermediaries from making improper payments or providing improper benefits for the purpose ofobtaining or retaining business. Our policies mandate compliance with these anti-corruption laws. However, we operate in many parts ofthe world that experience corruption. If we are found to be liable for violations of these laws either due to our own acts or our omissions ordue to the acts or omissions of others (including our joint ventures partners, our agents or other third party representatives), we could sufferfrom commercial, civil and criminal penalties or other sanctions, which could have a material adverse effect on our business, financialcondition and results of operations.

We are not fully insured against all risks associated with our business.We ordinarily maintain insurance against certain losses and liabilities arising from our operations. However, we do not insure against

all operational risks in the course of our business. Due to the high cost, high self-insured retention and limited coverage insurance forwindstorms in the GOM we have elected not to purchase windstorm insurance for our inland barges in the GOM. Although we haveretained the risk for physical loss or damage for these rigs arising from a named windstorm we have procured insurance coverage forremoval of a wreck caused by a windstorm. The occurrence of an event that is not fully covered by insurance could have a material adverseimpact on our business activities, financial position and results of operations.

We are subject to hazards customary for drilling operations, which could adversely affect our financial performance if we are notadequately indemnified or insured.

Substantially all of our operations are subject to hazards that are customary for oil and natural gas drilling operations, includingblowouts, reservoir damage, loss of well control, cratering, oil and natural gas well fires and explosions, natural disasters, pollution andmechanical failure. Our offshore operations also are subject to hazards inherent in marine operations, such as capsizing, sinking, grounding,collision and damage from severe weather conditions. Any of these risks could result in damage to or destruction of drilling equipment,personal injury and property damage, suspension of operations or environmental damage. We have had accidents in the past due to some ofthese hazards. We may not be able to insure against these risks or to obtain indemnification to adequately protect us against liability fromall of the consequences of the hazards and risks described above. The occurrence of an event not fully insured against or for which we arenot indemnified, or the failure of a customer or insurer to meet its indemnification or insurance obligations, could result in substantiallosses. In addition, insurance may not continue to be available to cover any or all of these risks. For example, pollution, reservoir damageand environmental risks generally are not fully insurable. Even if such insurance is available, insurance premiums or other costs may risesignificantly in the future, making the cost of such insurance prohibitive. For a description of our indemnification obligations andinsurance, please read Item 1. “Business — Insurance and Indemnification.”

Certain areas in and near the GOM are subject to hurricanes and other extreme weather conditions. When operating in and near theGOM, our drilling rigs and rental tools may be located in areas that could cause them to be susceptible to damage or total loss by thesestorms. In addition, damage caused by high winds and turbulent seas to our rigs, our shore bases and our

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corporate infrastructure could potentially cause us to curtail operations for significant periods of time until the effects of the damages canbe repaired. In addition, our rigs in arctic regions can be affected by seasonal weather so severe, conditions are deemed too unsafe foroperations.

Government regulations and environmental risks, which reduce our business opportunities and increase our operating costs, mightbecome more stringent in the future.

Government regulations control and often limit access to potential markets and impose extensive requirements concerning employeeprivacy and safety, environmental protection, pollution control and remediation of environmental contamination. Environmentalregulations, including species protections, prohibit access to some locations and make others less economical, increase equipment andpersonnel costs, and often impose liability without regard to negligence or fault. In addition, governmental regulations, such as thoserelated to climate change, may discourage our customers’ activities, reducing demand for our products and services. We may be liable fordamages resulting from pollution of offshore waters and, under United States regulations, must establish financial responsibility in order todrill offshore. See Part I, Business, “Environmental Considerations.”

Regulation of greenhouse gases and climate change could have a negative impact on our business.Some scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs) and

including carbon dioxide and methane, may be contributing to warming of the earth’s atmosphere and other climatic changes. In responseto such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attractingincreasing attention worldwide. Legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climatechange are in various phases of discussions or implementation at the international, national, regional and state levels.

In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which establishes a binding setof emission targets for GHGs, became binding on the countries that had ratified it. International discussions are underway to develop atreaty to replace the Kyoto Protocol after its expiration in 2020. In the United States, federal legislation imposing restrictions on GHGs isunder consideration. In addition, the EPA is taking steps to regulate GHGs as pollutants under the Clean Air Act (the CAA). To date, theEPA has issued (i) a “Mandatory Reporting of Greenhouse Gases” final rule, which establishes a new comprehensive scheme requiringoperators of stationary sources (including certain oil and natural gas production systems) in the United States emitting more thanestablished annual thresholds of carbon dioxide-equivalent GHGs to inventory and report their GHG emissions annually; (ii) an“Endangerment Finding” final rule, effective January 14, 2010, which states that current and projected concentrations of six key GHGs inthe atmosphere, as well as emissions from new motor vehicles and new motor vehicle engines, threaten public health and welfare, whichallowed the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crudeoil); and (iii) a final rule, effective August 2, 2010, to address permitting of GHG emissions from stationary sources under the CAA’sPrevention of Significant Deterioration (PSD) and Title V programs. This final rule “tailors” the PSD and Title V programs to apply tocertain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting.

Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treatiesor international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources,could have a negative impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demandfor oil and natural gas or otherwise result in reduced economic activity generally. In addition, such laws, regulations, treaties orinternational agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impacton our business. In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation orregulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns. Anincrease in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or resultin a disruption of our customers’ operations.

We are regularly involved in litigation, some of which may be material.We are regularly involved in litigation, claims and disputes incidental to our business, which at times may involve claims for

significant monetary amounts, some of which would not be covered by insurance. We undertake all reasonable steps to defend ourselves insuch lawsuits. Nevertheless, we cannot predict the ultimate outcome of such lawsuits and any resolution which is adverse to us could have amaterial adverse effect on our financial condition. See Note 15, “Commitments and Contingencies,” in Item 8 of this Form 10-K for adiscussion of the material legal proceedings affecting us.

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Increased regulation of hydraulic fracturing could result in reductions or delays in drilling and completing new oil and natural gaswells, which could adversely impact the demand for rental tools.

Hydraulic fracturing is a process sometimes used in the completion of oil and natural gas wells whereby water, sand and chemicalsare injected under pressure into subsurface formations to stimulate natural gas and, to a lesser extent, oil production. Various governmentalentities (within and outside the United States) are in the process of studying, restricting, regulating, or preparing to regulate hydraulicfracturing, directly and indirectly. For example, many state governments now require the disclosure of chemicals used in the fracturingprocess. The U.S. EPA has taken the position that hydraulic fracturing operations involving the use of diesel fuel in fracturing fluids aresubject to permitting requirements under the Safe Drinking Water Act; has adopted air emissions standards that apply to well completionactivities; is developing new standards for wastewater discharges associated with hydraulic fracturing; and is conducting a study on theimpacts of hydraulic fracturing on groundwater. The Bureau of Land Management has also proposed regulations for hydraulic fracturingactivities that would be unique to federal lands. In addition, some jurisdictions have imposed an express or de facto ban on hydraulicfracturing. These and other developments could cause operational delays or increased costs in exploration and production, which couldadversely affect the demand for our rental tools.

A cybersecurity incident could negatively impact our business and our relationships with customers.If our systems for protecting against cybersecurity risks prove not to be sufficient, we could be adversely affected by, among other

things, loss or damage of intellectual property, proprietary information, or customer data, having our business operations interrupted, andincreased costs to prevent, respond to, or mitigate cybersecurity attacks. These risks could have a material adverse effect on our business,consolidated results of operations, and consolidated financial condition.

Our acquisitions, dispositions, and investments may not result in the realization of savings, the creation of efficiencies, the generationof cash or income, or the reduction of risk, which may have a material adverse effect on our liquidity, consolidated results ofoperations, and consolidated financial condition.

We continually seek opportunities to maximize efficiency and value through various transactions, including purchases or sales ofassets, businesses, investments, or joint ventures. These transactions are intended to result in the realization of savings, the creation ofefficiencies, the offering of new products or services, the generation of cash or income, or the reduction of risk. Acquisition transactionsmay be financed by additional borrowings or by the issuance of our common stock. These transactions may also affect our consolidatedresults of operations.

These transactions also involve risks, and we cannot ensure that:• any acquisitions would result in an increase in

income;• any acquisitions would be successfully integrated into our operations and internal

controls;• the due diligence prior to an acquisition would uncover situations that could result in financial or legal exposure, or that we will

appropriately quantify the exposure from known risks;• any disposition would not result in decreased earnings, revenue, or cash

flow;• use of cash for acquisitions would not adversely affect our cash available for capital expenditures and other

uses;• any dispositions, investments, acquisitions, or integrations would not divert management resources;

or• any dispositions, investments, acquisitions, or integrations would not have a material adverse effect on our results of operations or

financial condition.

If we fail to integrate or realize the expected benefits from the ITS Acquisition, or if we incur any liabilities as a result of suchtransaction, our business, results of operations and profitability may be adversely affected.

We may not realize the expected benefits of the ITS Acquisition because the business may not perform financially as expected orbecause of integration difficulties and other challenges. The success of the ITS Acquisition will depend, in part, on our ability tosuccessfully integrate the acquired business with our existing businesses. The integration process is anticipated to be complex, costly andtime-consuming. Complications with the integration could result from the following circumstances, among others: failure to implement ourbusiness plan for the combined business; unanticipated issues in integrating and applying our internal control and other systems; failure toretain key customers; failure to retain key employees of ITS; and operating risks inherent in the acquired business. In addition, we may notaccomplish the integration smoothly, successfully or within the anticipated costs or timeframe. Furthermore, we may not be able to achieveanticipated cost savings or other synergies or realize growth opportunities that we expect with respect to our operation of ITS’ business.Additionally, the ITS Acquisition subjects us to potential liabilities to which we would not otherwise be exposed. In particular, our duediligence process with respect to the ITS Acquisition suggests that its internal controls may have failed to prevent violations of potentiallyapplicable international trade and anti-corruption laws, including those of the United Kingdom. We have

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investigated such violations and have and will, as appropriate, make any identified violations known to relevant authorities, cooperate withany resulting investigations and take proper remediation measures (including seeking any necessary government authorizations).

If we experience difficulties with the integration process or the anticipated growth opportunities and other potential synergies of theITS Acquisition, or if we incur any liabilities related to such acquisition, our business, results of operations and profitability may beadversely affected.

The market price of our common stock has fluctuated significantly.The market price of our common stock may continue to fluctuate in response to various factors and events, most of which are beyond

our control, including the following:• the other risk factors described in this Form 10-K, including changes in oil and natural gas

prices;• a shortfall in rig utilization, operating revenue or net income from that expected by securities analysts and

investors;• changes in securities analysts’ estimates of the financial performance of us or our competitors or the financial performance of

companies in the oilfield service industry generally;• changes in actual or market expectations with respect to the amounts of exploration and development spending by oil and natural

gas companies;• general conditions in the economy and in energy-related

industries;• general conditions in the securities

markets;• political instability, terrorism or

war; and• the outcome of pending and future legal proceedings, investigations, tax assessments and other

claims.

DISCLOSURE NOTE REGARDING FORWARD-LOOKING STATEMENTSThis Form 10-K contains statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act

of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Allstatements contained in this Form 10-K, other than statements of historical facts, are forward-looking statements for purposes of theseprovisions, including any statements regarding:

• stability of prices and demand for oil and naturalgas;

• levels of oil and natural gas exploration and productionactivities;

• demand for contract drilling and drilling-related services and demand for rentaltools;

• our future operating results andprofitability;

• our future rig utilization, dayrates and rental toolsactivity;

• entering into new, or extending existing, drilling or rental contracts and our expectations concerning when operations willcommence under such contracts;

• entry into new markets or potential exit from existingmarkets;

• growth through acquisitions of companies or assets; including the ITSacquisition;

• organic growth of ouroperations;

• construction or upgrades of rigs and expectations regarding when these rigs will commenceoperations;

• capital expenditures for acquisition of rental tools, rigs, construction of new rigs or major upgrades to existingrigs;

• entering into joint ventureagreements;

• the sale or potential sale of assets or references to assets held forsale;

• availability and sources of funds to refinance our debt and expectations of when debt will bereduced;

• our future

liquidity;• the outcome of pending or future legal proceedings, investigations, tax assessments and other

claims;• the availability of insurance coverage for pending or future

claims;• the enforceability of contractual indemnification in relation to pending or future claims;

and

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• compliance with covenants under our debtagreements.

In some cases, you can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,”“expect,” “intend,” “outlook,” “may,” “should,” “will” and “would” or similar words. Forward-looking statements are based on certainassumptions and analyses we make in light of our experience and perception of historical trends, current conditions, expected futuredevelopments and other factors we believe are relevant. Although we believe that our assumptions are reasonable based on informationcurrently available, those assumptions are subject to significant risks and uncertainties, many of which are outside of our control. Thefollowing factors, as well as any other cautionary language included in this Form 10-K, provide examples of risks, uncertainties and eventsthat may cause our actual results to differ materially from the expectations we describe in our forward-looking statements:

• worldwide economic and business conditions that adversely affect market conditions and/or the cost of doing business includingpotential country failures and downgrades;

• our inability to access the credit or bondmarkets;

• U.S credit market volatility resulting from the U.S national debt and potential further downgrades of the U.S. creditrating;

• the U.S. economy and the demand for naturalgas;

• low U.S. natural gas prices could adversely affect U.S. drilling and our barge rig and U.S. rental toolsbusinesses;

• worldwide demand foroil;

• fluctuations in the market prices of oil and natural gas, including the inability or unwillingness of our customers to fund drillingprograms in low price cycles;

• imposition of unanticipated traderestrictions;

• unanticipated operating hazards and uninsuredrisks;

• political instability, terrorism orwar;

• governmental regulations, including changes in accounting rules or tax laws or ability to remit funds to the U.S., that adverselyaffect the cost of doing business;

• changes in the tax laws that would allow double taxation on foreign sourcedincome;

• the outcome of investigations into possible violations oflaws;

• adverse environmentalevents;

• adverse weatherconditions;

• global healthconcerns;

• changes in the concentration of customer and supplierrelationships;

• ability of our customers and suppliers to obtain financing for theiroperations;

• ability of our customers to fund drillingplans;

• unexpected cost increases for new construction and upgrade and refurbishmentprojects;

• delays in obtaining components for capital projects and in ongoing operational maintenance and equipmentcertifications;

• shortages of skilledlabor;

• unanticipated cancellation of contracts byoperators;

• breakdown ofequipment;

• other operational problems including delays in start-up or commissioning ofrigs;

• changes incompetition;

• any failure to realize expected benefits fromacquisitions;

• the effect of litigation andcontingencies; and

• other similar factors, some of which are discussed in documents referred to or incorporated by reference into this Form 10-K andour other reports and filings with the SEC.

Each forward-looking statement speaks only as of the date of this Form 10-K, and we undertake no obligation to publicly update orrevise any forward-looking statements, whether as a result of new information, future events or otherwise. Before you

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decide to invest in our securities, you should be aware that the occurrence of the events described in these risk factors and elsewhere in thisForm 10-K could have a material adverse effect on our business, results of operations, financial condition and cash flows.

ITEM 1B. UNRESOLVED STAFFCOMMENTS

None.

ITEM 2. PROPERTIESWe lease corporate headquarters office space in Houston, Texas and own our U.S. rental tools headquarters office in New Iberia,

Louisiana. We lease regional headquarters space in Aberdeen, Scotland and Dubai, UAE related to our international rental tools business.Additionally, we own and/or lease office space and operating facilities in various other locations, domestically and internationally,including facilities where we hold inventories of rental tools and locations in close proximity to where we provide services to our customers.Additionally, we own and/or lease facilities necessary for administrative and operational support functions.

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Land and Barge RigsThe following table shows, as of December 31, 2013, the locations and drilling depth ratings of our rigs:

Name Type(1)

Year enteredinto service/

upgraded

Drillingdepth rating

(in feet) Location

International

Europe, Middle East, and Asia Rig 231 L 1981/1997 13,000 IndonesiaRig 253 L 1982/1996 15,000 IndonesiaRig 226 HH 1989/2010 18,000 Papua New GuineaRig 107 L 1983/2009 15,000 KazakhstanRig 216 L 2001/2009 25,000 KazakhstanRig 249 L 2000/2009 25,000 KazakhstanRig 257 B 1999/2010 30,000 KazakhstanRig 258 L 2001/2009 25,000 KazakhstanRig 247 L 1981/2008 18,000 Kurdistan Region of IraqRig 269 L 2008 21,000 Kurdistan Region of IraqRig 264 L 2007 20,000 TunisiaRig 265 L 2007 20,000 TunisiaRig 270 L 2011 21,000 Russia

Latin America Rig 268 L 1978/2009 30,000 ColombiaRig 271 L 1982/2009 30,000 ColombiaRig 121 L 1980/2007 18,000 ColombiaRig 122 L 1980/2008 18,000 MexicoRig 165 L 1978/2007 30,000 MexicoRig 221 L 1982/2007 30,000 MexicoRig 256 L 1978/2007 25,000 MexicoRig 266 L 2008 20,000 MexicoRig 267 L 2008 20,000 Mexico

U.S. Land and Barge Drilling Rig 8 B 1978/2007 14,000 GOMRig 12 B 1979/2006 18,000 GOMRig 15 B 1978/2007 15,000 GOMRig 20 B 1981/2007 13,000 GOMRig 21 B 1979/2012 14,000 GOMRig 50 B 1981/2006 20,000 GOMRig 51 B 1981/2008 20,000 GOMRig 54 B 1980/2006 25,000 GOMRig 55(2) B 1981/2001 25,000 GOMRig 72 B 1982/2005 25,000 GOMRig 76 B 1977/2009 30,000 GOMRig 77 B 2006/2006 30,000 GOMRig 272 L 2013 18,000 AlaskaRig 273 L 2012 18,000 Alaska

1) Type is defined as: L — land rig; B — barge rig; HH — heli-hoist landrig.

2) This rig is currently undergoing major refurbishment to make it available for service in2014.

The table above excludes five rigs currently not available for service. These rigs are Rig 140, located in Papua New Guinea, Rig 225 andRig 252, located in Indonesia, and Rig 230 and Rig 236, located in Kazakhstan.

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The following table presents our average utilization rates and rigs available for service for the years ended December 31, 2013 and2012:

December 31,

2013 2012U.S. Land & Barge Rigs

U.S. Barge Drilling Rigs Rigs available for service (1) 11.0 13.0Utilization rate of rigs available for service (2) 91% 78%

U.S. Drilling Rigs Rigs available for service (1) 1.9 1.1Utilization rate of rigs available for service (2) 100% 5%

International Land & Barge Rigs Europe, Middle East, and Asia Region

Rigs available for service (1) 14.0 15.5Utilization rate of rigs available for service (2) 49% 37%

Latin America Region Rigs available for service (1) 9.5 10.0Utilization rate of rigs available for service (2) 75% 67%

Total International Land & Barge Rigs Rigs available for service (1) 23.5 25.5Utilization rate of rigs available for service (2) 60% 49%

1) The number of rigs available for service is determined by calculating the number of days each rig was in our fleet and was undercontract or available for contract. For example, a rig under contract or available for contract for six months of a year is 0.5 rigsavailable for service during such year. Our method of computation of rigs available for service may not be comparable to othersimilarly titled measures of other companies.

2) Rig utilization rates are based on a weighted average basis assuming 365 days availability for all rigs available for service. Rigsacquired or disposed of are treated as added to or removed from the rig fleet as of the date of acquisition or disposal. Rigs that are inoperation or fully or partially staffed and on a revenue-producing standby status are considered to be utilized. Rigs under contract thatgenerate revenues during moves between locations or during mobilization or demobilization are also considered to be utilized. Ourmethod of computation of rig utilization may not be comparable to other similarly titled measures of other companies.

ITEM 3. LEGALPROCEEDINGS

For information on Legal Proceedings, see Note 15, Commitments and Contingencies, in the notes to the consolidated financialstatements included in Item 8 of this annual report on Form 10-K, which information is incorporated herein by reference.

ITEM 4. MINE SAFETYDISCLOSURES

Not applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUERPURCHASES OF EQUITY SECURITIES

Parker Drilling Company’s common stock is listed for trading on the New York Stock Exchange under the symbol “PKD.” Thefollowing table sets forth the high and low sales prices per share of our common stock, as reported on the New York Stock Exchangecomposite tape, for the periods indicated:

2013 2012

Quarter High Low High LowFirst $ 6.18 $ 4.27 $ 7.62 $ 5.69Second $ 5.20 $ 3.75 $ 6.27 $ 4.19Third $ 6.42 $ 4.92 $ 4.91 $ 4.00Fourth $ 8.50 $ 5.68 $ 4.60 $ 3.61

Most of our stockholders maintain their shares as beneficial owners in “street name” accounts and are not, individually, stockholdersof record. As of March 3, 2014, there were 1,601 holders of record of our shares and we had an estimated 20,675 beneficial owners.

Our Secured Credit Agreement and the indentures for the Senior Notes (except the amended indenture for the 9.125% Notes) restrictthe payment of dividends. We have not in the past paid dividends on our common stock and have no present intention to pay dividends onour common stock in the foreseeable future.

Issuer Purchases of Equity Securities

The Company currently has no active share repurchase programs. When restricted stock awarded by the Company becomes taxablecompensation to personnel, shares may be withheld to satisfy the associated withholding tax liabilities. Information on our purchases ofequity securities by means of such share withholdings is provided in the table below:

Issuer Purchases of Equity Securities

Period

Total Numberof Shares

Purchased Average PricePaid Per Share

October 1-31, 2013 39,811 $ 7.20November 1-30, 2013 221 $ 7.07December 1-31, 2013 92,691 $ 8.11Total 132,723 $ 7.83

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ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected historical consolidated financial data derived from the audited financial statements of ParkerDrilling Company for each of the five years in the period ended December 31, 2013. The following financial data should be read inconjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statementsand related notes appearing elsewhere in this Form 10-K.

Year Ended December 31,

2013 2012 2011 (1) 2010 2009 (Dollars in Thousands, Except Per Share Amounts)

Income Statement Data Total revenues $ 874,172 $ 677,761 $ 686,234 $ 659,475 $ 752,910Total operating income (loss) 101,872 107,273 (41,837) 45,107 39,322Other expense, net (49,085) (36,296) (23,575) (33,602) (29,495)Income tax expense (benefit) 25,608 33,879 (14,767) 26,213 560Net income (loss) 27,179 37,098 (50,645) (14,708) 9,267Net income (loss) attributable to controlling interest 27,015 37,313 (50,451) (14,461) 9,267Basic earnings per share:

Income (loss) from continuing operations $ 0.23 $ 0.32 $ (0.43) $ (0.13) $ 0.08Net income (loss) $ 0.23 $ 0.32 $ (0.43) $ (0.13) $ 0.08

Diluted earnings per share: Income (loss) from continuing operations $ 0.22 $ 0.31 $ (0.43) $ (0.13) $ 0.08Net income (loss) $ 0.22 $ 0.31 $ (0.43) $ (0.13) $ 0.08

Balance Sheet Data Cash and cash equivalents $ 148,689 $ 87,886 $ 97,869 $ 51,431 $ 108,803Property, plant and equipment, net (2) 871,356 793,197 722,774 819,112 716,798Assets held for sale (2) — — — — —Total assets 1,534,756 1,255,733 1,216,246 1,274,555 1,243,086Total long-term debt including current portion of long-term debt

653,781 479,205 482,723 472,862 423,831Total equity 633,142 590,633 544,050 588,066 595,899

1) The 2011 results reflect a $170.0 million ($109.1 million, net of taxes of $60.9 million) non-cash pretax impairment charge related toour two arctic-class drilling rigs located in Alaska. See Note 4 to the Consolidated Financial Statements in Item 8 of this Form 10-K.

2) The balances for the years ended December 31, 2012, 2011, and 2010 have been adjusted to reflect the reclassification to property,plant & equipment of certain assets previously classified as assets held for sale. During 2013, management concluded, based on thefacts and circumstances at the time, it was no longer probable that the sales of five rigs that had been previously reclassified to assetsheld for sale would be consummated within a reasonable time period.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OFOPERATIONS

OVERVIEW AND OUTLOOK

OverviewWe continued to make progress in 2013, leading to better operating performance and financial results. Our international drilling

operations increased average utilization to 73 percent for the 2013 fourth quarter, up from 42 percent for the prior year's fourth quarter. OurGOM barge drilling operations increased average utilization to 89 percent for the 2013 fourth quarter, up from 83 percent for the prioryear's fourth quarter, and earned a 14 percent higher average dayrate. Our U.S. rental tools operation continued its growth in the GOMoffshore drilling market, recording a 23 percent increase in revenues generated from that market in the 2013 fourth quarter, compared withthe same period of 2012. The most challenging market conditions we encountered in 2013 were in the U.S. land drilling market, where aslow, steady decline in drilling activity impacted rental tools utilization and market pricing. In addition, we made a significant addition tothe Company's position in the international rental tools market with the April 22 acquisition of ITS.

During 2013 we undertook, progressed or completed several important projects, including:• We made significant growth investments in our Rental Tools segment. This includes the acquisition of ITS and the purchase of

capital equipment to leverage our growing position in the GOM offshore drilling market and to capture growth opportunities forITS. The integration of ITS into the Company's operations required significant effort during the year and was substantiallycompleted at year-end.

• We improved average utilization of our international drilling rig fleet. Of the fifteen rigs located in the Eastern Hemisphere, onlyfour were under contract at the start of 2013. By year-end, nine of those rigs were under contract; one rig had been added to thefleet under contract for work in Russia; three rigs had been sold; and we were in discussions concerning future work for theremaining idle rigs.

• In early 2013, we commenced operation of Rig 272, the second of our two arctic-class drilling rigs on the Alaskan North Slope. Itjoined Rig 273, commissioned in December, 2012. Each rig is operating on a long-term contract and is expected to continue to bea solid cash flow contributor.

• In February 2013, we expanded our O&M activities with the addition of a contract to operate three platform rigs offshoreCalifornia for ExxonMobil. In addition, we continued our involvement in the development of the Exxon Neftegas Limited (ENL)Berkut platform, which will soon move to Sakhalin Island, Russia and join our O&M activities there.

• Late in 2013, we began the overhaul and refurbishment of barge rig 55-B. We believe this rig, when completed, will offerconsiderable value to operators in our GOM market and significantly contribute to the operating and financial performance of ourU.S. barge drilling business. We expect the rig to be ready to work some time during the 2014 second quarter.

• During the year we took steps to sharpen our business focus, selling two international land drilling rigs and one internationalbarge drilling rig, no longer suited to our strategy.

• The Company’s implementation of a new enterprise resource planning (ERP) system continued with the start-up of two importantmodules, human resources and finance, during the year. This Oracle-based system is providing us with new and better tools toplan and manage our business.

• In July 2013, we issued $225.0 million of 7.50% Notes and used the proceeds to refinance the $125.0 million term loanassociated with the ITS Acquisition, to repay the term loan portion of our Secured Credit Facility and for future retirement ofdebt. Subsequently, in January, 2014, we issued $360 million of 6.75% Notes, and used the proceeds along with a $40.0 milliondraw on our Secured Credit Agreement and cash on hand to repurchase our 9.125% Notes. This transaction resulted in lower debtoutstanding, reduced annual interest expense and extended our debt maturity schedule.

OutlookWe are encouraged by industry forecasts calling for expanded drilling activity in the U.S. and international markets. The projected

growth, when it occurs, should benefit us broadly. Nevertheless, current market conditions have yet to reflect those forecasts. Based on ourrecent experience and current markets, we expect revenue and earnings to grow in 2014, with relatively stronger results later in the year aswe improve operating performance and leverage the projected market growth.

We expect current conditions impacting our Rental Tools segment to continue in early 2014 before improving later in the year.Sluggish drilling activity in the U.S. land drilling market has led to competitive conditions for rental tools suppliers.

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While there has been no significant change recently, we expect market conditions to improve as drilling activity picks up. We expect ourexpanding participation in the U.S. offshore GOM drilling market will provide a growing contribution to the segment’s results. Severalinternational locations which recently completed large contracts are gearing up for expected further work. This will add to an expectedincrease in work activity from the growing inflow and deployment of capital equipment, purchased in 2013 and now beginning to arrive atour international rental tools locations.

For our U.S. Barge Drilling segment, winter conditions and customer delays during the start of the year have reduced first quarterdrilling opportunities in the GOM inland waters. We do not expect these conditions to persist and anticipate an improvement in drillingactivity during the year should lead to better utilization and support for our industry-leading dayrates. The addition of Rig 55B to our fleetduring the 2014 second quarter should augment the segment’s contributions in the latter part of the year.

Our U.S. Drilling segment, is expected to continue to deliver solid operating results and cash flow, with two arctic-class drilling rigsworking in Alaska and management of three offshore platforms in California on multi-year contracts.

We have successfully raised the level of utilization for our international rig fleet and expect tender activity and contract renewals toprovide ample opportunities to maintain utilization without significant breaks in activity. We expect to continue to provide reliable revenueand earnings contributions to this business through our O&M contracts, as well.

As we strengthen our ability to consistently provide our customers with innovative, reliable and efficient responses to their operationalneeds, we expect additional opportunities to produce enhanced returns and continued growth.

RESULTS OF OPERATIONSYear ended December 31, 2013 Compared with Year ended December 31, 2012

Revenues of $874.2 million for the year ended December 31, 2013 increased $196.4 million, or 29.0 percent, from the comparable2012 period. Operating gross margin, including depreciation and amortization increased 11.1 percent to $168.4 million for the year endedDecember 31, 2013 as compared to $151.6 million for the year ended December 31, 2012.

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The following is an analysis of our operating results for the comparable periods:

Year Ended December 31,

2013 2012 (Dollars in Thousands)Revenues:

Rental Tools $ 310,041 35% $ 246,900 36%U.S. Barge Drilling 136,855 16% 123,672 18%U.S. Drilling 66,928 8% 1,387 1%International Drilling 333,962 38% 291,772 43%Technical Services 26,386 3% 14,030 2%Construction Contract (1) — —% — —%

Total revenues 874,172 100% 677,761 100%Operating gross margin excluding depreciation andamortization(2):

Rental Tools gross margin 147,017 47% 158,016 64%U.S Barge Drilling gross margin 65,595 48% 54,100 44%U.S. Drilling gross margin 11,901 18% (8,151) n/aInternational Drilling gross margin 71,078 21% 60,492 21%Technical Services gross margin 2,181 8% 116 1%Construction Contract gross margin (1) 4,728 n/a — —%

Total operating gross margin excluding depreciation andamortization 302,500 35% 264,573 39%

Depreciation and amortization (134,053) (113,017) Total operating gross margin 168,447 151,556

General and administrative expense (68,025) (46,257) Provision for reduction in carrying value of certainassets (2,544) — Gain on disposition of assets, net 3,994 1,974

Total operating income $ 101,872 $ 107,273

(1) As of December 31, 2013, the Company has five active operating segments: Rental Tools, U.S. Barge Drilling, U.S. Drilling,International Drilling, and Technical Services. We historically reported a sixth segment, Construction Contract, for which there was noactivity for the nine months ended September 30, 2013 or the year ended December 31, 2012. As a result of our reversal of reservesrelating to this segment in the fourth quarter of 2013, this segment has been included in this report. See “—Operations —ConstructionContract”.

(2) Operating gross margin, excluding depreciation and amortization is computed as revenues less direct operating expenses, andexcludes depreciation and amortization expense, where applicable; operating gross margin percentages are computed as operating grossmargin as a percent of revenues. The operating gross margin amounts and operating gross margin percentages should not be used as asubstitute for those amounts reported under generally accepted accounting principles in the U.S. (U.S. GAAP). However, we monitor ourbusiness segments based on several criteria, including operating gross margin. Management believes that this information is useful to ourinvestors because it more accurately reflects cash generated by segment. Such operating gross margin amounts are reconciled to our mostcomparable U.S. GAAP measure as follows:

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RentalTools

U.S. BargeDrilling

U.S.Drilling

InternationalDrilling

TechnicalServices

ConstructionContract(2)

(Dollars in Thousands) Year ended December 31, 2013

Operating gross margin(1) $ 91,164 $ 51,257 $ (4,484) $ 23,732 $ 2,050 $ 4,728Depreciation and amortization 55,853 14,338 16,385 47,346 131 —Segment operating gross marginexcluding depreciation andamortization $ 147,017 $ 65,595 $ 11,901 $ 71,078 $ 2,181 $ 4,728

Year ended December 31, 2012 Operating gross margin(1) $ 113,899 $ 39,608 $ (15,168) $ 13,138 $ 79 $ —Depreciation and amortization 44,117 14,492 7,017 47,354 37 —Segment operating gross marginexcluding depreciation andamortization $ 158,016 $ 54,100 $ (8,151) $ 60,492 $ 116 $ —(1) Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization

expense.(2) The Construction Contract segment does not incur depreciation and

amortization.

OperationsRental Tools

Rental Tools segment revenues increased $63.1 million, or 25.6 percent, to $310.0 million for the year ended December 31, 2013compared to $246.9 million for the year ended December 31, 2012. The increase is primarily due to the contribution of $88.0 million ofrevenues from ITS and higher revenues from a growing participation in the expanding U.S. GOM offshore drilling market. The increase inrevenues was primarily offset by the impact of the continuing competitive conditions in the U.S. land drilling market due to declines indrilling activity in almost all major basins.

Rental Tools segment operating gross margin excluding depreciation and amortization decreased $11.0 million, or 7.0 percent, to$147.0 million for the year ended December 31, 2013 as compared with $158.0 million for the year ended December 31, 2012. Thedecrease was primarily due to a reduction in gross margin excluding depreciation and amortization for our U.S. Rental Tools business of$31.5 million, primarily due to the increase in competitive conditions which led to lower product pricing for rental tools and relatedactivities and a decline in rental tool utilization. This decrease was partially offset by the contribution of $20.5 million of gross marginexcluding depreciation and amortization attributable to ITS from the date of acquisition.

U.S. Barge DrillingU.S. Barge Drilling segment revenues increased $13.2 million, or 10.7 percent, to $136.9 million for the year ended December 31,

2013, as compared with revenues of $123.7 million for the year ended December 31, 2012. The increase in revenues was primarily due toan increase in rig fleet utilization and higher average dayrates for the fleet during 2013. Both of these factors reflect a general increase inoverall drilling activity in the U.S. GOM inland waters and an increase in our dayrates for multi-well contracts based on our ability todeliver higher levels of performance compared with our competitors.

U.S. Barge Drilling segment operating gross margin excluding depreciation and amortization increased $11.5 million, or 21.2 percent,to $65.6 million for the year ended December 31, 2013, compared with $54.1 million for the year ended December 31, 2012. This increaseis primarily a result of improved average dayrates and the continued control of operating costs.

U.S. DrillingU.S. Drilling segment revenues increased $65.5 million to $66.9 million for the year ended December 31, 2013, compared with $1.4

million for the year ended December 31, 2012. This increase in revenues is primarily due to the commencement of operations by our twoarctic-class drilling rigs in Alaska, one in the fourth quarter of 2012 and the other in the first quarter of 2013. Prior to that, during the firstthree quarters of 2012, both rigs were under construction and not generating revenues. Additionally, in February 2013 we began an O&Mcontract supporting three platform operations located offshore California.

U.S. Drilling segment operating gross margin excluding depreciation and amortization was $11.9 million for the year endedDecember 31, 2013 compared with a loss of $8.2 million for the year ended December 31, 2012. The increase in gross margin excludingdepreciation and amortization for this segment is mainly due to the contributions from the arctic-class drilling rigs in Alaska and theCalifornia O&M contract described above which were not earning revenues or contributing to gross

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margin during 2012. The loss in 2012 resulted from expenditures associated with re-entering the Alaska market prior to the rigs going towork in Alaska in late 2012 and into early 2013.

International DrillingInternational Drilling segment revenues increased $42.2 million, or 14.5 percent, to $334.0 million for the year ended December 31,

2013, compared with $291.8 million for the year ended December 31, 2012. The increase in revenues is primarily due to higher revenuesgenerated by our O&M contracts coupled with higher drilling revenues through the operation of rigs we own.

Revenues related to Parker-owned rigs increased $19.4 million, or 10.6 percent, to $202.9 million for the year ended December 31,2013 compared with $183.5 million for the year ended December 31, 2012. The increase in revenues was primarily due to the contributionof revenues from a previously idle rig added to our Sakhalin Island operations and two previously idle rigs added to our operations in theKurdistan Region of Iraq partially offset by lower utilization in Algeria. Additionally, there were increased revenues related to our arctic-class barge rig in the Caspian Sea and the contribution of revenues from a previously idle rig in the Karachaganak field in Kazakhstan.

O&M revenues increased $22.8 million, or 21.1 percent, to $131.1 million, for the year ended December 31, 2013 compared to$108.3 million for the year ended December 31, 2012. The increase in revenues was primarily due to higher reimbursable revenuesassociated with our services contracts related to the Berkut platform project in South Korea and Orlan platform project on Sakhalin Island.Reimbursable revenues are generated through our purchasing support for the O&M rigs we operate for our customers. Approximately$46.4 million and $31.3 million of O&M revenues were attributable to reimbursable costs for the years ended December 31, 2013 and2012, respectively. Reimbursable revenues add to revenues but have a minimal impact on operating margins.

International Drilling operating gross margin excluding depreciation and amortization increased $10.6 million, or 17.5 percent, to$71.1 million for the year ended December 31, 2013, compared with $60.5 million for the year ended December 31, 2012. The increase inoperating gross margin excluding depreciation and amortization for the year ended December 31, 2013 was from our Parker-owned rigoperations slightly offset by a decrease in O&M margins.

Operating gross margin excluding depreciation and amortization related to Parker-owned rigs was $51.0 million and $39.6 million forthe years ended December 31, 2013 and 2012, respectively. The increase in operating gross margin excluding depreciation and amortizationwas primarily due to the contribution of revenues from a previously idle rig in Kazakhstan, in our Karachaganak field operations, and apreviously idle rig in our Sakhalin Island operations. Additionally, there were increased revenues from higher utilization of our arctic-classbarge rig in the Caspian Sea. The increase was partially offset by costs associated with the mobilization and start-up of the two rigs locatedin the Kurdistan Region of Iraq, decreased utilization resulting from two Algeria rigs stacked in Tunisia and lower revenues and highercosts in our Latin America region.

Operating gross margin excluding depreciation and amortization generated by our O&M operations was $20.0 million and $20.9million for the years ended December 31, 2013 and 2012, respectively. The decrease in operating gross margin excluding depreciation andamortization is primarily due to the completion of an O&M contract in China that was active during all of 2012, a decrease in revenuesfrom our Coral Sea project in Papua New Guinea, and higher operating costs related to the Orlan platform project in Sakhalin. Thesedecreases were partially offset by an increase in labor revenues related to the Berkut platform project in South Korea.

Technical ServicesTechnical Services segment revenues increased $12.4 million, or 88.1 percent, to $26.4 million for the year ended December 31,

2013, compared with $14.0 million for the year ended December 31, 2012. This increase was primarily due to increased activity under thevendor services phase of the Berkut platform project which started during the 2012 third quarter and a new customer FEED project thattogether more than offset the mid-2012 completion of two other customer FEED projects.

Operating gross margin excluding depreciation and amortization for this segment increased by $2.1 million to $2.2 million for theyear ended December 31, 2013, compared with nominal gross margin excluding depreciation and amortization for the year endedDecember 31, 2012. The increase is primarily the result of change in the scope of projects noted above. The Technical Services segmentincurs minimal depreciation and amortization which primarily relates to office furniture and fixtures.

Construction ContractThis segment was created for and only includes the Liberty extended-reach drilling rig construction project which our customer

canceled in 2011 prior to final completion. Our construction contract segment revenues were zero for the years ended December 31, 2013and 2012. This segment reported $4.7 million and zero operating gross margin excluding depreciation and

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amortization for the years ended December 31, 2013 and 2012, respectively. The operating gross margin excluding depreciation andamortization generated during the year ended December 31, 2013 resulted from close-out of the Liberty project.

The Liberty rig construction contract was a fixed-fee and reimbursable contract that we accounted for on a percentage of completionbasis. We recognized $335.5 million in revenues and $11.7 million of operating gross margin over the life of the contract. Over the courseof the project, we established a project contingency reserve, which we maintained for potential claims by our subcontractors, vendors andcustomer. Due to the closure of all material claims, for which payments have been made or otherwise resolved or which are barred by theapplicable statute of limitations, during the fourth quarter of 2013, we reversed the contingency reserve resulting in the operating grossmargin excluding depreciation and amortization recognized for the year ended December 31, 2013. Other Financial Data

General and administrative expense increased $21.8 million to $68.0 million for the year ended December 31, 2013, compared with$46.3 million for the year ended December 31, 2012. The general and administrative expense increase was due primarily to approximately$22.5 million of costs incurred during 2013 related to the ITS Acquisition slightly offset by decreased costs relating to the settlement withthe DOJ and SEC, and decreased legal fees associated with the related SEC and DOJ investigations (see further discussion in Note 15 -Commitments and Contingencies).

Provision for reduction in carrying value of certain assets was $2.5 million which was comprised of non-cash charges recognized forthree rigs reclassified from assets held for sale to assets held and used for which carrying values exceeded fair values. During 2013,management concluded, based on the facts and circumstances at the time, it was no longer probable that the sales of the rigs sale would beconsummated.

Net gains recorded on asset dispositions for the years ended December 31, 2013 and 2012 were $4.0 million and $2.0 million,respectively. During 2013, we sold two rigs located in New Zealand, a building located in Tulsa and a barge rig located in Mexico. Thesesales resulted in gains totaling $1.2 million. Additionally, during the normal course of operations, we periodically sell equipment deemed tobe excess, obsolete, or not currently required for operations.

Interest expense increased $14.3 million to $47.8 million for the year ended December 31, 2013 compared with $33.5 million for theyear ended December 31, 2012. The increase in interest expense primarily resulted from an $11.6 million increase in debt-related interestexpense primarily related to the full-year impact of the $125.0 million of 9.125% Notes issued in the second quarter of 2012, the $225.0million 7.50% Notes issued in July 2013 and the $125.0 million debt incurred in April 2013 used to initially fund the ITS Acquisition.Additionally, we experienced a $7.9 million decrease in interest capitalized on internal construction projects resulting from the completionof the two new arctic-class drilling rigs in Alaska, which increased overall interest expense. The increase in interest expense is partiallyoffset by a decrease due to the repayment of our 2.125% Convertible Notes in the 2013 second quarter and a decrease in amortization ofdebt issuance costs. Interest income was $2.5 million and $0.2 million for the years ended December 31, 2013 and 2012, respectively.Interest income in 2013 primarily related to interest earned on an IRS refund received during the year.

Loss on extinguishment of debt was $5.2 million and $2.1 million for the years ended December 31, 2013 and December 31, 2012,respectively. The loss on extinguishment of debt for 2013 is related to the extinguishment in July 2013 of the $125 million debt incurred inApril 2013 used to initially fund the ITS Acquisition. The loss on extinguishment of debt for 2012 resulted from the repurchase of $122.9million of outstanding 2.125% Convertible Notes in May 2012.

Other income and expense was $1.5 million of income and $0.8 million of expense for the years ended December 31, 2013 andDecember 31, 2012, respectively. Other income in 2013 was primarily related to the recognition of non-refundable deposits from a buyer inconnection with the sale of three rigs for which the sales agreement was terminated in the 2013 fourth quarter.

Income tax expense was $25.6 million for the year ended December 31, 2013, compared with $33.9 million for the year endedDecember 31, 2012. The 2013 tax expense decrease was primarily due to lower pre-tax earnings in addition to discrete items relating toenactment of new tax legislation in Mexico, research and development tax credits and other less significant items related to return-to-accrual adjustments.

Our effective tax rate was 48.5% for the year ended December 31, 2013, compared with 47.7% for the year ended December 31,2012. Our tax rate is affected by recurring items, such as tax rates in state and non-U.S. jurisdictions and the relative amounts of income weearn in those jurisdictions, which we expect to be fairly consistent in the near term. It is also affected by discrete items, such as return-to-accrual adjustments and changes in reserves for uncertain tax positions, which may occur in any given year but are not consistent from yearto year.

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Year Ended December 31, 2012 Compared with Year Ended December 31, 2011Revenues of $677.8 million for the year ended December 31, 2012 decreased $8.5 million, or 1.2 percent, from the comparable 2011

period. The years ended December 31, 2012 and 2011 included construction contract revenues of zero and $9.6 million, respectively, forthe Liberty rig construction project that was canceled by our customer in 2011. Excluding that individual project, revenues from ongoingoperations for the year ended December 31, 2012 would have been approximately the same as in 2011. Operating gross margin, includingdepreciation and amortization decreased 3.7 percent to $151.6 million for the year ended December 31, 2012 as compared to $157.4 millionfor the year ended December 31, 2011.The following is an analysis of our operating results for the comparable periods:

Year Ended December 31,

2012 2011 (Dollars in Thousands)Revenues:

Rental Tools $ 246,900 36% $ 237,068 35%U.S. Barge Drilling 123,672 18% 93,763 14%U.S. Drilling 1,387 1% — —%International Drilling 291,772 43% 318,481 46%Technical Services 14,030 2% 27,284 4%Construction Contract — —% 9,638 1%

Total revenues 677,761 100% 686,234 100%Operating gross margin excluding depreciation andamortization:

Rental Tools gross margin 158,016 64% 162,577 69%U.S Barge Drilling gross margin 54,100 44% 28,619 31%U.S. Drilling gross margin (8,151) n/a (1,692) n/aInternational Drilling gross margin 60,492 21% 73,602 23%Technical Services gross margin 116 n/a 5,680 n/aConstruction Contract gross margin — —% 771 —%Total operating gross margin excluding depreciation andamortization 264,573 39% 269,557 39%Depreciation and amortization (113,017) (112,136)

Total operating gross margin 151,556 157,421 General and administrative expense (46,257) (31,567) Impairments and other charges — (170,000) Provision for reduction in carrying value of certain assets — (1,350) Gain on disposition of assets, net 1,974 3,659

Total operating income $ 107,273 $ (41,837)

Operating gross margin excluding depreciation and amortization is computed as revenues less direct operating expenses, and excludesdepreciation and amortization expense, where applicable; operating gross margin percentages are computed as operating gross margin as apercent of revenues. The operating gross margin amounts and operating gross margin percentages should not be used as a substitute forthose amounts reported under generally accepted accounting principles in the U.S. (U.S. GAAP). However, we monitor our businesssegments based on several criteria, including operating gross margin. Management believes that this information is useful to our investorsbecause it more accurately reflects cash generated by segment. Such operating gross margin amounts are reconciled to our most comparableU.S. GAAP measure as follows:

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RentalTools

U.S. BargeDrilling

U.S.Drilling

InternationalDrilling

TechnicalServices

ConstructionContract(2)

(Dollars in Thousands)Year Ended December 31, 2012

Operating gross margin(1) $ 113,899 $ 39,608 $ (15,168) $ 13,138 $ 79 $ —Depreciation and amortization 44,117 14,492 7,017 47,354 37 —Operating gross margin excludingdepreciation and amortization $ 158,016 $ 54,100 $ (8,151) $ 60,492 $ 116 $ —

Year Ended December 31, 2011 Operating gross margin(1) $ 120,822 $ 11,115 $ (3,915) $ 22,948 $ 5,680 $ 771Depreciation and amortization 41,755 17,504 2,223 50,654 — —Operating gross margin excludingdepreciation and amortization $ 162,577 $ 28,619 $ (1,692) $ 73,602 $ 5,680 $ 771(1) Operating gross margin is calculated as revenues less direct operating expenses, including depreciation and amortization

expense.(2) The Construction Contract segment does not incur depreciation and

amortization.

OperationsRental Tools

Rental Tools segment revenues increased $9.8 million, or 4.1 percent, to $246.9 million for the year ended December 31, 2012compared to revenues for the year ended December 31, 2011. The increase is primarily due to an increase in rentals to offshore GOMcustomers and greater tool sales and repair revenues. This was partially offset by the impact of soft U.S. natural gas prices that led toreduced demand from the U.S. land drilling market and lower rental tools utilization in key operating areas.

Rental Tools segment operating gross margin excluding depreciation and amortization decreased by $4.6 million, or 2.8 percent, forthe year ended December 31, 2012 compared with operating gross margin excluding depreciation and amortization for the year endedDecember 31, 2011, primarily due to increased price competition in key U.S. land drilling markets, and the impact of an increase in lower-margin total sales and repair revenues.

U.S. Barge DrillingU.S. Barge Drilling segment revenues increased $29.9 million, or 31.9 percent, to $123.7 million for the year ended December 31,

2012, compared with revenues for the year ended December 31, 2011. The increase in revenues was primarily due to an increase in rig fleetutilization and overall higher average dayrates for 2012. Both of these factors reflect a general increase in overall drilling activity in theU.S. GOM inland waters. Additionally, our dayrates benefit from our ability to renegotiate dayrates during multi-well contracts based onour ability to deliver higher levels of performance.

U.S. Barge Drilling segment operating gross margin excluding depreciation and amortization increased $25.5 million or 89.0 percentto $54.1 million for the year ended December 31, 2012, compared with segment operating gross margin excluding depreciation andamortization for the year ended December 31, 2011. This increase is primarily a result of overall improved rig fleet utilization and averagedayrates and the continued control of operating costs.

U.S. DrillingU.S. Drilling segment began generating revenue in early December 2012 as the first of the two arctic-class drilling rigs commenced

drilling operations. The second rig completed client acceptance testing and began drilling in February 2013. Revenues were $1.4 millionand zero for the years ended December 31, 2012 and 2011, respectively. The introduction of these rigs to the Alaskan North Slope isexpected to improve drilling efficiency, operating consistency and safety in this remote and challenging environment.

U.S. Drilling segment operating gross margin excluding depreciation and amortization was a loss of $8.2 million and $1.7 million forthe years ended December 31, 2012 and 2011, respectively. Operating expenses include start-up costs associated with re-entering theAlaskan market, such as salaries and employee hiring-related expenditures, training and rental of facilities in Alaska to support ouroperations. Additionally, early in the third quarter of 2012 we began incurring depreciation expense and ceased capitalizing interest costsrelated to one of the rigs when it was presented to the customer to begin the acceptance testing process.

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International DrillingInternational Drilling segment revenues decreased $26.7 million, or 8.4 percent, to $291.8 million for the year ended December 31,

2012, compared with the year ended December 31, 2011. The lower revenues are primarily due to a decrease in revenue generated by ourO&M contracts and a decline in our drilling revenues generated through the operation of rigs we own.

O&M revenues decreased to $108.3 million, or 14.7 percent for the year ended December 31, 2012 compared to $127.0 million forthe year ended December 31, 2011. The decrease in revenues was primarily due to the completion in 2011 of a drilling rig relocationproject on Sakhalin Island, Russia and lower rates associated with our services contracts on Sakhalin Island. This was partially offset byincreased operating and reimbursable revenues associated with the Orlan platform contract as it moved from warm-stack mode to fully-operational mode during 2012, the benefits of a new one-rig service contract in China, and the operation during much of 2012 of acustomer-owned rig in Papua New Guinea. O&M projects included $31.3 million and $51.9 million of reimbursable costs for the yearsended December 31, 2012 and 2011. Reimbursable costs add to revenues but have little direct impact on operating margins.

Revenues related to Parker-owned rigs decreased to $183.5 million or 4.2 percent for the year ended December 31, 2012 comparedwith $191.5 million for the year ended December 31, 2011. Revenues declined in the EMEA region primarily due to lower utilization ofour arctic-class barge rig in the Caspian Sea and reduced dayrates on our rig in Papua New Guinea. The decrease was partially offset byincreased revenues in Algeria as a result of the mobilization and start-up of two rigs during 2012 and a contribution from demobilizationfees in the Latin America region as two rigs completed work during the year.

International Drilling operating gross margin excluding depreciation and amortization decreased $13.1 million, or 17.8 percent, to$60.5 million for the year ended December 31, 2012, compared with $73.6 million for the year ended December 31, 2011. The decrease inoperating gross margin excluding depreciation and amortization for the year ended December 31, 2012 was due to decreased margins forboth our O&M operations and our Parker-owned rig operations. Operating gross margin excluding depreciation and amortization generatedby our O&M operations were $20.9 million and $25.7 million for the years ended December 31, 2012 and 2011, respectively. The decreaseis primarily due to a decrease in handling fees associated with lower reimbursable costs charged back to customers and lower projectmanagement fees related to the drilling rig relocation project on Sakhalin Island, Russia that was completed prior to December 31, 2011,and lower rates associated with our service contracts on Sakhalin Island as we transitioned from higher value operating contracts to cost-plus contracts during 2012. This was partially offset by the operating gross margin excluding depreciation and amortization associated withthe Orlan platform contract as it moved from warm-stack mode to fully-operational mode during 2012 and the benefits of a new one-rigservice contract in China.

Our operating gross margin excluding depreciation and amortization related to Parker-owned rigs was $39.6 million and $47.9million for the years ended December 31, 2012 and 2011, respectively. The decrease in operating gross margin excluding depreciation andamortization was primarily the result of lower rig utilization related to our arctic-class barge rig in the Caspian Sea and a non-cash chargeto reserve certain value-added tax assets resulting from a strategic decision to move two rigs out of the Kazakhstan market. Partiallyoffsetting this decrease were increased operating gross margin excluding depreciation and amortization resulting from the start-up of tworigs in Algeria during 2012 and increased utilization and demobilization revenues in Latin America. In addition, results for 2011 included$1.9 million of expense related to equity tax assessments in Latin America.

Technical ServicesTechnical Services segment revenues decreased $13.3 million, or 48.6 percent, to $14.0 million for the year ended December 31,

2012, compared with $27.3 million for the year ended December 31, 2011. This decrease was primarily due to expiration of the “pre-operations” phase of the Liberty project at the end of the second quarter of 2011 and the transition of the Berkut platform project from itsengineering phase to a less revenue-intensive construction oversight and assistance phase. Also contributing to the decrease was thecompletion of a pre-FEED project at the end of the second quarter of 2012.

Operating gross margin excluding depreciation and amortization for this segment decreased by $5.6 million to $0.1 million for theyear ended December 31, 2012, compared with $5.7 million for the year ended December 31, 2011. The decrease in operating gross marginexcluding depreciation and amortization was primarily due to the completion of a pre-FEED project at the end of the second quarter of2012, the transition of the Berkut platform project into a less revenue-intensive construction oversight and assistance phase, and the costs toretain technical capabilities as we transition between projects. The Technical Services segment incurs minimal depreciation andamortization primarily related to office furniture and fixtures.

Construction ContractThis segment includes only the Liberty extended-reach drilling rig construction project. Construction Contract segment revenues were

zero for the year ended December 31, 2012 compared with $9.6 million for the year ended December 31, 2011. This segment reported zeroand $0.8 million operating gross margin for the years ended December 31, 2012 and December 31,

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2011, respectively. The operating gross margin generated during the year ended December 31, 2011 resulted from the preliminary close-outof the Liberty project and recognition of final percentage of completion revenues. The Construction Contract segment does not incurdepreciation and amortization.

The Liberty rig construction contract was a fixed fee and reimbursable contract that we accounted for on a percentage of completionbasis. As of December 31, 2011, we had recognized $335.5 million in project-to-date revenues. Over the life of the contract, we recognized$11.7 million of operating gross margin on the contract.

Other Financial DataDuring the fourth quarter of 2011 we recorded a non-cash pre-tax impairment charge of $170.0 million ($109.1 million, net of taxes

of $60.9 million) to adjust our arctic-class drilling rigs in Alaska to their fair value from the existing net book value (see Note 4 to theConsolidated Financial Statements). In 2011, we recognized a $1.4 million reduction in carrying value of assets related to a final settlementof a customer bankruptcy matter as it was deemed that the Company’s rights to mineral reserves no longer supported the outstandingreceivable.

Gain on asset dispositions for the year ended December 31, 2012 and 2011 was $2.0 million and $3.7 million, respectively. Weperiodically sell equipment deemed to be excess, obsolete, or not currently required for operations.

Interest expense increased $10.9 million for the year ended December 31, 2012 compared with the year ended December 31, 2011.The increase primarily resulted from a $5.2 million increase in interest on the additional $125.0 million of 9.125% Notes, which have ahigher interest rate than our 2.125% Convertible Notes that were repaid during 2012, and a $9.0 million decrease in interest capitalized onmajor projects, resulting from a reduction in the value of the arctic-class drilling rigs in Alaska following the impairment charge recordedduring the fourth quarter of 2011 and the placement of one of the arctic-class drilling rigs into service during the fourth quarter of 2012.The net increase was partially offset by a decrease in amortization of the debt discount on the 2.125% Convertible Notes as they weretendered or matured during 2012 and amortization of the debt premium related to the additional $125.0 million of 9.125% Notes. Interestincome was $0.2 million and $0.3 million for the years ended December 31, 2012 and 2011, respectively.

Loss on extinguishment of debt of $2.1 million resulted from the repurchase prior to maturity of $122.9 million of the 2.125%Convertible Notes pursuant to a tender offer on May 9, 2012 and the write-off of debt issuance costs related to refinancing our SecuredCredit Agreement in December 2012. The loss included a $0.4 million premium paid to repurchase the 2.125% Convertible Notes prior tomaturity, $1.4 million accelerated amortization of the related debt discount and debt issuance costs of the 2.125% Convertible Notes, and$0.3 million accelerated amortization of the debt issuance costs related to our Secured Credit Agreement.

General and administration expense increased $14.7 million for the year ended December 31, 2012, compared with general andadministrative expense for the year ended December 31, 2011. The general and administrative cost increase was due primarily to aproposed settlement with the DOJ and SEC recorded during the fourth quarter of 2012, offset by a decrease in legal fees associated with therelated SEC and DOJ investigations.

Income tax expense was $33.9 million for the year ended December 31, 2012, compared with an income tax benefit of $14.8 millionfor the year ended December 31, 2011. The 2012 tax expense was primarily due to the mix of our domestic and international pretaxearnings and losses, the mix of international tax jurisdictions in which we operate, and adjustments related to the settlement of ourexamination with the U.S. Internal Revenue Service for tax periods through 2010 including carryover adjustments impacting the 2011period. The 2011 period tax benefit was driven primarily by the $170.0 million non-cash pretax charge for our arctic-class drilling rigs inAlaska resulting in a $60.9 million federal and state tax benefit, offset by operating income (excluding the impairment), differences in themix of our domestic and international pretax earnings and losses, as well as the mix of international tax jurisdictions in which we operate.Included in tax expense for the year ended December 31, 2012 was an expense of $1.5 million related to an uncertain tax position and abenefit of $7.0 million related to the effective settlement of uncertain tax positions.

LIQUIDITY AND CAPITAL RESOURCESWe periodically evaluate our liability requirements, capital needs and availability of resources in view of expansion plans, debt

service requirements, and other operational cash needs. To meet our short and long term liquidity requirements, including payment ofoperating expenses and repaying debt, we rely primarily on cash from operations. However, we have recently sought, and may in the futureseek, to raise additional capital. We expect that for the foreseeable future, cash generated from operations will be sufficient to provide usthe ability to fund our operations, provide the working capital necessary to support our strategy, and fund planned capital expenditures.

In connection with the ITS Acquisition, on April 18, 2013, we entered into a $125 million term loan, fully funded by Goldman SachsBank USA as Sole Lead Arranger and Administrative Agent (Goldman Term Loan) with a stated maturity date of April 18, 2018. On July30, 2013, we issued the 7.50% Notes. Net proceeds from the 7.50% Notes offering were used to

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repay in full the Goldman Term Loan, to repay $45.0 million of term loan borrowings under our Secured Credit Agreement and for generalcorporate purposes.

On January 22, 2014, we issued the 6.75% Notes. Net proceeds from the offering, plus a $40.0 million draw under the Secured CreditAgreement and cash on hand, were utilized to purchase $416.2 million aggregate principal amount of our outstanding 9.125% Notespursuant to a tender and consent solicitation offer commenced on January 7, 2014. The tender offer price was $1,061.98, inclusive of a$30.00 consent payment, for each $1,000.00 principal amount of 9.125% Notes tendered, plus accrued and unpaid interest. On January 22,2014, we paid $453.7 million for the tendered 9.125% Notes, comprised of $416.2 million for the aggregate principal amount of thetendered 9.125% Notes, $25.8 million of tender and consent premiums and $11.7 million of accrued interest. After payment for thetendered 9.125% Notes, $8.8 million aggregate principal amount of our 9.125% Notes remained outstanding.

LiquidityAs of December 31, 2013, we had cash and cash equivalents of $148.7 million, an increase of $60.8 million from December 31, 2012.

The following table provides a cash flow summary for the last three years:

2013 2012 2011 (Dollars in thousands)Operating Activities $ 161,497 $ 189,699 $ 225,885Investing Activities (265,418) (187,606) (184,614)Financing Activities 164,724 (12,076) 5,167Net change in cash and cash equivalents $ 60,803 $ (9,983) $ 46,438

Operating ActivitiesCash flows from operating activities were $161.5 million in 2013, compared with $189.7 million in 2012. We have reinvested a

substantial portion of our operating cash flows to expand our business through acquisition and to enhance our fleet of drilling rigs and rentaltools equipment. We do not pay dividends to our shareholders. Changes in working capital were a use of cash of $34.0 million and a sourceof cash of $1.0 million for the years ended December 31, 2013 and December 31, 2012, respectively. Uses of operating cash flows during2013 primarily related to the ITS Acquisition which resulted in increased receivables, inventory and accounts payable. Changes in cashfrom operating activities were also impacted by non-cash charges such as depreciation expense, gains on asset sales, deferred tax benefit,stock compensation expense, debt extinguishment and amortization of debt issuance costs. Depreciation expense increased due to our twoAlaska rigs commencing work in late 2012 and early 2013. Additionally, during 2013, we more aggressively disposed of assets deemed notcore to the current strategy resulting in an increase in gain on disposition of assets. It is our current intention to continue to utilize ouroperating cash flows to finance further investments into our rental tools inventories, rig purchases or upgrades as well as other strategicinvestments aligned to our strategies.

Cash flows from operating activities were $189.7 million in 2012, compared with $225.9 million in 2011. Before changes in operatingassets and liabilities, cash from operating activities was impacted primarily by net income of $37.1 million plus non-cash charges of $151.6million. Non-cash charges primarily consisted of $113.0 million of depreciation expense and deferred tax benefit of $15.8 million. Netchanges in operating assets and liabilities provided $1.0 million and $32.2 million of cash in 2012 and 2011 respectively.

Investing ActivitiesCash flows used in investing activities were $265.4 million for 2013 compared with $187.6 million in 2012. Our primary use of cash

was $118.0 million for the ITS Acquisition and $155.6 million for capital expenditures. Capital expenditures in 2013 were primarily fortubular and other products for our rental tools business, rig-related enhancements and maintenance and costs related to our new enterpriseresource planning system. Sources of cash included $8.2 million of proceeds from asset sales.

Cash flows used in investing activities were $187.6 million for 2012. Our primary use of cash was $191.5 million for capitalexpenditures. Capital expenditures in 2012 were primarily for the construction of our two arctic-class drilling rigs, tubular and otherproducts for our rental tools business, and costs related to our new enterprise resource planning system. In addition, we incurred capital tosupport ongoing drilling activities. Sources of cash included $3.9 million of proceeds from asset sales.

Capital expenditures for 2014 are estimated to range from $180.0 million to $200.0 million and will primarily be directed to ourRental Tools segment inventory and maintenance capital on our rigs. Any discretionary spending will be evaluated based upon adequatereturn requirements and available liquidity. We believe that our operating cash flows and borrowings under our revolving credit facility(Revolver), will provide us sufficient cash and available liquidity to sustain operation and fund our

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capital expenditures for 2014, though there can be no assurance that we will continue to generate cash flows at sufficient levels or be able toobtain additional financing if necessary. See “Item 1A. Risk Factors” for a discussion of additional risks related to our business.

Financing ActivitiesCash flows provided by financing activities were $164.7 million for 2013. Cash flows provided by financing activities primarily

related to the $125 million Goldman Term Loan issued during the 2013 second quarter in connection with the ITS Acquisition and the$225.0 million 7.50% Notes issued during the 2013 third quarter. Cash used in financing activities included pay-off of the Goldman TermLoan in the 2013 third quarter, principal payments made under our Term Loan (defined below) and payments of debt issuance costs.

Cash flows used in financing activities were $12.1 million for 2012. Our primary financing activities included the repayment of$125.0 million of 2.125% Convertible Notes and $18.0 million in quarterly payments against our Term Loan then-outstanding. In addition,we received proceeds from the issuance of an additional $125.0 million aggregate principal amount of 9.125% Notes at a price of 104.0percent, resulting in gross proceeds of $130.0 million, less $4.9 million of associated debt issuance costs. We also made a $7.0 milliondraw on our Revolver (defined below).

6.75% Senior Notes, due July 2022On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Notes. Net proceeds from the 6.75% Notes

offering plus a $40.0 million draw under the Secured Credit Agreement and cash on hand, were utilized to purchase $416.2 millionaggregate principal amount of our 9.125% Notes pursuant to a tender and consent solicitation offer commenced on January 7, 2014. Thetender offer price was $1,061.98, inclusive of a $30.00 consent payment, for each $1,000 principal amount of 9.125% Notes, plus accruedand unpaid interest. On January 22, 2014, we paid $453.7 million for the tendered 9.125% Notes, comprised of $416.2 million of aggregateprincipal amount of the tendered 9.125% Notes, $25.8 million of tender and consent premiums and $11.7 million of accrued interest. Afterpayment for the tendered 9.125% Notes, $8.8 million aggregate principal amount of our 9.125% Notes remains outstanding.

The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing andfuture senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guaranteeindebtedness under our Secured Credit Agreement and our other outstanding Senior Notes. Interest on the 6.75% Notes is payable onJanuary 15 and July 15 of each year, beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes are estimated to be $7.1million and will be amortized over the term of the notes using the effective interest rate method.

At any time prior to January 15, 2017, we may redeem up to 35 percent of the aggregate principal amount of the 6.75% Notes at aredemption price of 106.75 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cashproceeds of certain equity offerings by us. On and after January 15, 2018, we may redeem all or a part of the 6.75% Notes upon appropriatenotice, at a redemption price of 103.375 percent of the principal amount, and at redemption prices decreasing each year thereafter to parbeginning January 15, 2020. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent ofthe aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make otherdistributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur orguarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or otherpayment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x)engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as eventsof default. These covenants are subject to a number of important exceptions and qualifications.

7.50% Senior Notes, due August 2020On July 30, 2013, we issued $225.0 million aggregate principal amount of 7.50% Notes. Net proceeds from the 7.50% Notes offering

were primarily used to repay the $125.0 million aggregate principal amount of the Goldman Term Loan, to repay $45.0 million of TermLoan borrowings under our Secured Credit Agreement and for general corporate purposes.

The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing andfuture senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guaranteeindebtedness under our Secured Credit Agreement. Interest on the 7.50% Notes is payable on February 1 and August 1 of each year,beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes were $5.3

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million ($5.2 million, net of amortization as of December 31, 2013) and will be amortized over the term of the notes using the effectiveinterest rate method.

At any time prior to August 1, 2016, we may redeem up to 35 percent of the aggregate principal amount of the 7.50% Notes at aredemption price of 107.50 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cashproceeds of certain equity offerings by us. On and after August 1, 2016, we may redeem all or a part of the 7.50% Notes upon appropriatenotice, at a redemption price of 103.750 percent of the principal amount, and at redemption prices decreasing each year thereafter to parbeginning August 1, 2018. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of theaggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make otherdistributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur orguarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or otherpayment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x)engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Eventsof Default. These covenants are subject to a number of important exceptions and qualifications.

9.125% Senior Notes, due April 2018On March 22, 2010, we issued $300.0 million aggregate principal amount of the 9.125% Notes. Net proceeds from the 9.125% Notes

offering were primarily used to redeem the $225.0 million aggregate principal amount of our 9.625% Senior Notes due 2013 and to repay$42.0 million of borrowings under our then-existing senior secured credit agreement dated May 15, 2008 (Prior Credit Agreement).

On April 25, 2012, we issued an additional $125.0 million aggregate principal amount of 9.125% Notes under the same indenture at aprice of 104.0 percent of par, resulting in gross proceeds of $130.0 million. Net proceeds from the offering were utilized to refinance$125.0 million aggregate principal amount of the 2.125% Convertible Senior Notes due July 2012 (2.125% Convertible Notes). Werepurchased $122.9 million aggregate principal amount of the 2.125% Convertible Notes tendered pursuant to a tender offer on May 9,2012 and paid off the remaining $2.1 million at their stated maturity on July 15, 2012.

On January 7, 2014, we commenced a tender and consent solicitation with respect to the 9.125% Notes. The tender offer price was$1,061.98, inclusive of a $30.00 consent payment, for each $1,000 principal amount of 9.125% Notes, plus accrued and unpaid interest. OnJanuary 22, 2014, we paid $453.7 million for the tendered 9.125% Notes, comprised of $416.2 million of aggregate principal amount of the9.125% Notes, $25.8 million of tender and consent premiums and $11.7 million of accrued interest. After payment for the tendered 9.125%Notes, $8.8 million aggregate principal amount of our 9.125% Notes remains outstanding.

At any time after April 1, 2014, we may redeem all or a part of the 9.125% Notes upon appropriate notice, at a redemption price of104.563 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning April 1, 2016. The9.125% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing and futuresenior unsecured indebtedness. The 9.125% Notes are jointly and severally guaranteed by substantially all of our material domesticsubsidiaries other than subsidiaries generating revenues primarily outside the United States. Interest on the 9.125% Notes is payable onApril 1 and October 1 of each year. Debt issuance costs related to the 9.125% Notes of approximately $11.6 million ($7.7 million, net ofamortization) are being amortized over the term of the notes using the effective interest rate method.

2.125% Convertible Senior Notes, due July 2012On July 5, 2007, we issued $125.0 million aggregate principal amount of the 2.125% Convertible Notes. As noted above, on May 9,

2012, we repurchased $122.9 million aggregate principal amount of the 2.125% Convertible Notes pursuant to a tender offer. The tenderoffer price was $1,003.27 for each $1,000 principal amount of 2.125% Convertible Notes, plus accrued and unpaid interest. This repurchaseresulted in the recording of debt extinguishment costs of $1.8 million related to the accelerated amortization of both the unamortized debtissuance costs and debt discount associated with the 2.125% Convertible Notes. The remaining $2.1 million aggregate principal amount ofnon-tendered 2.125% Convertible Notes was subsequently paid off at their stated maturity on July 15, 2012.

Goldman Term LoanIn connection with the ITS Acquisition described in Note 2 on April 18, 2013, we entered into the Goldman Term Loan. The

Goldman Term Loan was repaid on July 30, 2013 with net proceeds from the issuance of $225.0 million aggregate principal amount of7.50% Notes. In connection with the repayment of the Goldman Term Loan we incurred debt extinguishment costs of $5.2 million.

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Amended and Restated Credit AgreementOn December 14, 2012, we entered into the Secured Credit Agreement consisting of a senior secured $80.0 million revolving credit

facility (Revolver) and a senior secured term loan facility (Term Loan) of $50.0 million. The Secured Credit Agreement matures onDecember 14, 2017. The Secured Credit Agreement provides that, subject to certain conditions, including the approval of theAdministrative Agent and the lenders’ acceptance (or additional lenders being joined as new lenders), the amount of the Term Loan orRevolver can be increased by an additional $50.0 million, so long as after giving effect to such increase, the Aggregate Commitments shallnot be in excess of $180.0 million.

Our obligations under the Secured Credit Agreement are guaranteed by substantially all of our material domestic subsidiaries, each ofwhich has executed guaranty agreements; and are secured by first priority liens on our accounts receivable, specified barge rigs and rentalequipment. The Secured Credit Agreement contains customary affirmative and negative covenants with which we were in compliance as ofDecember 31, 2013 and December 31, 2012. The Secured Credit Agreement terminates on December 14, 2017.

Our loans pursuant to the Secured Credit Agreement, the 9.125% Notes, the 7.50% Notes and the 6.75% Notes are guaranteed bysubstantially all of our direct and indirect domestic subsidiaries other than immaterial subsidiaries and subsidiaries generating revenuesprimarily outside the United States, each of which have executed guaranty agreements; and are secured by first priority liens on ouraccounts receivable, specified barge rigs and rental equipment. The Secured Credit Agreement contains customary affirmative and negativecovenants with which we were in compliance as of December 31, 2013 and December 31, 2012. The Secured Credit Agreement matures onDecember 14, 2017.

On July 19, 2013, we entered into an amendment to our Secured Credit Agreement which, among other things, permits us or any ofour subsidiaries (other than certain immaterial subsidiaries) to incur indebtedness pursuant to additional unsecured senior notes in anaggregate principal amount not to exceed $250.0 million at any one time outstanding; provided that any such notes shall (x) have ascheduled maturity occurring after the maturity date of our Secured Credit Agreement, (y) contain terms (including covenants and events ofdefault) no more restrictive, taken as a whole, to us and our subsidiaries than those contained in our Secured Credit Agreement and (z) haveno scheduled amortization, no sinking fund requirements and no maintenance financial covenants. In addition, pursuant to the amendment,and subject to the terms and conditions set forth in the Secured Credit Agreement, to the extent we repay the principal amount of TermLoans outstanding under our Secured Credit Agreement, until April 30, 2014 we may re-borrow, in the form of additional term loans, up to$45.0 million of the principal amount of such outstanding term loans we have repaid, provided that such $45.0 million borrowing amountwill decrease by $2.5 million at the end of each quarter beginning September 30, 2013 and ending March 31, 2014, such that the borrowingavailability on December 31, 2013 was $40.0 million and on April 30, 2014 would be $37.5 million.

RevolverOur Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base

Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Under the Secured Credit Agreement, the Applicable Rate varies from arate per annum ranging from 2.50 percent to 3.00 percent for LIBOR rate loans and 1.50 percent to 2.00 percent for base rate loans,determined by reference to the consolidated leverage ratio (as defined in the Credit Agreement). Revolving loans are available subject to aborrowing base calculation based on a percentage of eligible accounts receivable, certain specified barge drilling rigs and rental equipmentof the Company and its subsidiary guarantors. There were no revolving loans outstanding at December 31, 2013 and December 31, 2012.Letters of credit outstanding as of December 31, 2013 and December 31, 2012 totaled $4.6 million and $4.5 million, respectively.

Term LoanThe Term Loan originated at $50.0 million on December 14, 2012 and required quarterly principal payments of $2.5 million

beginning March 31, 2013. Interest on the Term Loan accrued at a Base Rate plus 2.00 percent or LIBOR plus 3.00 percent. There were noborrowings on the Term Loans at December 31, 2013. The outstanding balance on the Term Loans as of December 31, 2012 was$50.0 million. Pursuant to the July 19, 2013 amendment, and subject to the terms and conditions set forth in the Secured Credit Agreement,until April 30, 2014 we may re-borrow, in the form of additional term loans, up to $45.0 million of the principal amount of the term loanswe repaid, provided that such $45.0 million borrowing amount will decrease by $2.5 million at the end of each quarter beginningSeptember 30, 2013 and ending March 31, 2014, such that the borrowing availability on December 31, 2013 was $40.0 million and onApril 30, 2014 would be $37.5 million.

Other LiquidityOur principal amount of long-term debt, including current portion, was $650.0 million as of December 31, 2013, which consisted of:• $425.0 million aggregate principal amount of 9.125% Senior Notes, due April 1,

2018; and• $225.0 million aggregate principal amount of 7.50% Senior Notes, due August 1,

2020.

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As of December 31, 2013, we had approximately $264.1 million of liquidity, which consisted of $148.7 million of cash and cashequivalents on hand, $75.4 million of availability under the Revolver and $40.0 million of reborrowing capability under our Term Loan. Asof January 31, 2014, subsequent to the issuance of the 6.75% Notes and tender of 9.125% Notes, we had approximately $157.0 million ofliquidity, which consisted of $81.6 million of cash and cash equivalents on hand, $75.4 million available under our Secured CreditAgreement. We do not have any unconsolidated special-purpose entities, off-balance sheet financing arrangements or guarantees of third-party financial obligations. We have no energy, commodity, or foreign currency derivative contracts at December 31, 2013.

The following table summarizes our future contractual cash obligations as of December 31, 2013:

Total Less than

1 Year Years1 - 3

Years3 - 5

More than5 Years

(Dollars in Thousands)Contractual cash obligations:

Long-term debt — principal(1) $ 650,000 $ — $ — $ 425,000 $ 225,000Long-term debt — interest(1) 292,735 55,750 111,313 91,922 33,750Operating leases(2) 52,105 13,979 17,080 13,058 7,988Purchase commitments(3) 43,100 43,100 — — —

Total contractual obligations $ 1,037,940 $ 112,829 $ 128,393 $ 529,980 $ 266,738Commercial commitments:

Standby letters of credit(4) 4,583 4,583 — — —Total commercial commitments $ 4,583 $ 4,583 $ — $ — $ —1) Long-term debt includes the principal and interest cash obligations of the 9.125% Notes. The remaining unamortized premium of $3.8

million on the additional $125.0 million of 9.125% Notes is not included in the contractual cash obligations schedule.2) Operating leases consist of lease agreements in excess of one year for office space, equipment, vehicles and personal

property.3) We have purchase commitments outstanding as of December 31, 2013, related to rental tools and rig upgrade

projects.4) We have an $80.0 million Revolver pursuant to our Secured Credit Agreement. As of December 31, 2013, there were no borrowings

under the Revolver and $4.6 million of availability has been used to support letters of credit that have been issued, resulting in anestimated $75.4 million of availability. The Revolver expires December 14, 2017.

OTHER MATTERSBusiness Risks

See Item 1A, Risk Factors, for a discussion of risks related to our business.

Critical Accounting PoliciesOur discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements,

which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of thesefinancial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at thedate of the financial statements and the reported amounts of revenues and expenses during the reporting period. On an ongoing basis, weevaluate our estimates, including those related to fair value of assets, bad debt, materials and supplies obsolescence, property andequipment, goodwill, income taxes, workers’ compensation and health insurance and contingent liabilities for which settlement is deemedto be probable. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under thecircumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are notreadily apparent from other sources. While we believe that such estimates are reasonable, actual results could differ from these estimates.

We believe the following are our most critical accounting policies as they can be complex and require significant judgments,assumptions and/or estimates in the preparation of our consolidated financial statements. Other significant accounting policies aresummarized in Note 1 in the notes to the consolidated financial statements.

Fair value measurements. For purposes of recording fair value adjustments for certain financial and non-financial assets andliabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfera liability in an orderly transaction between market participants in the principal market for the asset or liability. Our valuation techniquerequires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjustedquoted prices for identical assets or liabilities in active markets (Level 1),

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(2) direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities in active markets oridentical assets or liabilities in less active markets (Level 2) and (3) unobservable inputs that require significant judgment for which there islittle or no market data (Level 3). When multiple input levels are required for a valuation, we categorize the entire fair value measurementaccording to the lowest level of input that is significant to the measurement even though we may have also utilized significant inputs thatare more readily observable.

Impairment of Property, Plant and Equipment. We review the carrying amounts of long-lived assets for potential impairmentannually, typically during the fourth quarter, or when events occur or circumstances change that indicate the carrying value of such assetsmay not be recoverable. For example, evaluations are performed when we experience sustained significant declines in utilization anddayrates, and we do not contemplate recovery in the near future. In addition, we evaluate our assets when we reclassify property andequipment to assets held for sale or as discontinued operations as prescribed by accounting guidance related to accounting for theimpairment or disposal of long-lived assets. We determine recoverability by evaluating the undiscounted estimated future net cash flows.When impairment is indicated, we measure the impairment as the amount by which the assets carrying value exceeds its fair value.Management considers a number of factors such as estimated future cash flows, appraisals and current market value analysis in determiningfair value. Assets are written down to fair value if the concluded current fair value is below the net carrying value.

Asset impairment evaluations are, by nature, highly subjective. They involve expectations about future cash flows generated by ourassets and reflect management’s assumptions and judgments regarding future industry conditions and their effect on future utilizationlevels, dayrates and costs. The use of different estimates and assumptions could result in materially different carrying values of our assets.

Accrual for Self-Insurance. Our operations are subject to many hazards inherent to the drilling industry, including blowouts,explosions, fires, loss of well control, loss of hole, damaged or lost drilling equipment and damage or loss from inclement weather ornatural disasters. Any of these hazards could result in personal injury or death, damage to or destruction of equipment and facilities,suspension of operations, environmental damage and damage to the property of others. Generally, drilling contracts provide for the divisionof responsibilities between a drilling company and its customer, and we seek to obtain indemnification from our customers by contract forcertain of these risks. To the extent that we are unable to transfer such risks to customers by contract or indemnification agreements, weseek protection through insurance. However, these insurance or indemnification agreements may not adequately protect us against liabilityfrom all of the consequences of the hazards described above. Moreover, our insurance coverage generally provides that we assume aportion of the risk in the form of an insurance coverage deductible.

Based on the risks discussed above, we estimate our liability in excess of insurance coverage and accrue for these amounts in ourconsolidated financial statements. Accruals related to insurance are based on the facts and circumstances specific to the insurance claimsand our past experience with similar claims. The actual outcome of insured claims could differ significantly from the amounts estimated.We accrue actuarially determined amounts in our consolidated balance sheet to cover self-insurance retentions for workers’ compensation,employers’ liability, general liability, automobile liability and health benefits claims. These accruals use historical data based upon actualclaim settlements and reported claims to project future losses. These estimates and accruals have historically been reasonable in light of theactual amount of claims paid.

As the determination of our liability for insurance claims could be material and is subject to significant management judgment and incertain instances is based on actuarially estimated and calculated amounts, management believes that accounting estimates related toinsurance accruals are critical.

Accounting for Income Taxes. We are a U.S. company and we operate through our various foreign legal entities and their branchesand subsidiaries in numerous countries throughout the world. Consequently, our tax provision is based upon the tax laws and rates in effectin the countries in which our operations are conducted and income is earned. The income tax rates imposed and methods of computingtaxable income in these jurisdictions vary. Therefore, as a part of the process of preparing the consolidated financial statements, we arerequired to estimate the income taxes in each of the jurisdictions in which we operate. This process involves estimating the actual currenttax exposure together with assessing temporary differences resulting from differing treatment of items, such as depreciation, amortizationand certain accrued liabilities for tax and accounting purposes. Our effective tax rate for financial statement purposes will continue tofluctuate from year to year as our operations are conducted in different taxing jurisdictions. Current income tax expense represents eitherliabilities expected to be reflected on our income tax returns for the current year, nonresident withholding taxes or changes in prior year taxestimates which may result from tax audit adjustments. Our deferred tax expense or benefit represents the change in the balance of deferredtax assets or liabilities reported on the consolidated balance sheet. Valuation allowances are established to reduce deferred tax assets whenit is more likely than not that some portion or all of the deferred tax assets will not be realized. In order to determine the amount of deferredtax assets or liabilities, as well as the valuation allowances, we must make estimates and assumptions regarding future taxable income,where rigs will be deployed and other matters. Changes in these estimates and assumptions, as well as changes in tax laws, could require usto adjust the deferred tax assets and liabilities or valuation allowances, including as discussed below.

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Our ability to realize the benefit of our deferred tax assets requires that we achieve certain future earnings levels prior to theexpiration of our net operating loss (NOL) and foreign tax credit (FTC) carryforwards. In the event that our earnings performanceprojections do not indicate that we will be able to benefit from our NOL and FTC carryforwards, valuation allowances are establishedfollowing the "more likely than not" criteria. We periodically evaluate our ability to utilize our NOL and FTC carryforwards and, inaccordance with accounting guidance related to accounting for income taxes, will record any resulting adjustments that may be required todeferred income tax expense in the period for which an existing estimate changes.

We do not currently provide for U.S. deferred taxes on unremitted earnings of our foreign subsidiaries as such earnings are deemed tobe permanently reinvested. If such earnings were to be distributed, we would be subject to U.S. taxes, which may have a material impact onour results of operations. We annually review our position and may elect to change our future tax position.

We apply the accounting standards related to uncertainty in income taxes. This accounting guidance requires that management makeestimates and assumptions affecting amounts recorded as liabilities and related disclosures due to the uncertainty as to final resolution ofcertain tax matters. Because the recognition of liabilities under this interpretation may require periodic adjustments and may not necessarilyimply any change in management’s assessment of the ultimate outcome of these items, the amount recorded may not accurately reflectactual outcomes.

Revenue Recognition. Contract drilling revenues and expenses, comprised of daywork drilling contracts and engineering and relatedproject service contracts, are recognized as services are performed and collection is reasonably assured. For certain contracts, we receivepayments contractually designated for the mobilization of rigs and other drilling equipment. Mobilization payments received, and directcosts incurred for the mobilization, are deferred and recognized over the term of the related drilling contract; however, costs incurred torelocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed as incurred. Reimbursementsreceived for out-of-pocket expenses are recorded as both revenues and direct costs. For contracts that are terminated prior to the specifiedterm, early termination payments received by us are recognized as revenues when all contractual requirements are met. Revenues fromrental activities are recognized ratably over the rental term which is generally less than six months. Technical Services contracts includeengineering, consulting, and project management scopes of work and revenue is typically recognized on a time and materials basis.

During 2013 the Company entered into a FEED contract including long-lead equipment procurement services accounted for underthe milestone method of revenue recognition. Milestone payments are based on achievement of specified procurement coordination anddelivery events in regards to our customer's newly manufactured drilling rig. The quantity of specific long-lead items to be procured isspelled out in the contract and the payment terms are identified with each piece of equipment as well as each specific milestone.Management concluded that each of these payments, constitute substantive milestones. This conclusion was based primarily on the factsthat (i) each triggering event represents a specific outcome that can be achieved only through successful performance by the Company ofone or more of its deliverables, (ii) achievement of each triggering event was subject to inherent risk and uncertainty and would result inadditional payments becoming due to the Company, (iii) each of the milestone payments is non-refundable, (iv) substantial effort isrequired to complete each milestone, (v) the amount of each milestone payment is reasonable in relation to the value created in achievingthe milestone, and (vi) the milestone payments relate solely to past performance.

Recent Accounting PronouncementsFor a discussion of the new accounting pronouncements that have had or are expected to have an effect on our consolidated financial

statements, see Notes to Consolidated Financial Statements — Note 20 — Recent Accounting Pronouncements.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKETRISK

Foreign Currency Exchange Rate RiskOur international operations expose us to foreign currency exchange rate risk. There are a variety of techniques to minimize the

exposure to foreign currency exchange rate risk, including customer contract payment terms and the possible use of foreign currencyexchange rate risk derivative instruments. Our primary foreign currency exchange rate risk management strategy involves structuringcustomer contracts to provide for payment in both U.S. dollars and local currency. The payment portion denominated in local currency isbased on anticipated local currency requirements over the contract term. Due to various factors, including customer acceptance, localbanking laws, other statutory requirements, local currency convertibility and the impact of inflation on local costs, actual foreign currencyexchange rate risk needs may vary from those anticipated in the customer contracts, resulting in partial exposure to foreign exchange risk.Fluctuations in foreign currencies typically have not had a material impact on our overall results. In situations where payments of localcurrency do not equal local currency requirements, foreign currency exchange rate risk derivative instruments, specifically foreign currencyexchange rate risk forward contracts, or spot purchases, may be used to mitigate foreign exchange rate currency risk. A foreign currencyexchange rate risk forward contract obligates us to exchange predetermined amounts of specified foreign currencies at specified exchange

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rates on specified dates or to make an equivalent U.S. dollar payment equal to the value of such an exchange. We do not enter intoderivative transactions for speculative purposes. At December 31, 2013, we had no open foreign currency exchange rate risk derivativecontracts.

Interest Rate RiskWe are exposed to changes in interest rates through our fixed rate long-term debt. Typically, the fair market value of fixed rate long-

term debt will increase as prevailing interest rates decrease and will decrease as prevailing interest rates increase. The fair value of ourlong-term debt is estimated based on quoted market prices where applicable, or based on the present value of expected cash flows relatingto the debt discounted at rates currently available to us for long-term borrowings with similar terms and maturities. The estimated fair valueof our $425.0 million principal amount of 9.125% Notes, based on quoted market prices, was $446.3 million at December 31, 2013. Theestimated fair value of our $225.0 million principal amount of 7.50% Notes, based on quoted market prices, was $236.3 million atDecember 31, 2013. A hypothetical 100 basis point increase in interest rates relative to market interest rates at December 31, 2013 woulddecrease the fair market value of our 9.125% Notes by approximately $46.1 million and decrease the fair market value of our 7.50% Notesby approximately $29.0 million.

In 2011, we entered into two variable-to-fixed interest rate swap agreements as a strategy to manage the floating rate risk on the TermLoan borrowings under the Secured Credit Agreement. The two agreements fixed the interest rate on a notional amount of $73.0 million ofborrowings at 3.878 percent for the period beginning June 27, 2011 and terminating May 14, 2013. The notional amount of the swapagreements decreased correspondingly with amortization of the Term Loan. We did not apply hedge accounting to the agreements and,accordingly, reported the mark-to-market change in the fair value of the interest rate swaps in earnings. As of December 31, 2013 the swapagreements had expired and as of December 31, 2012, the fair value of the interest rate swap was a liability of $0.1 million.

Impact of Fluctuating Commodity PricesWe are exposed to fluctuations that arise from economic or political risks that have, and will, impact underlying commodity prices

for natural gas, oil and natural gas/oil mixtures. The Company’s business is subject to price fluctuations in commodities, and may beimpacted by prolonged pricing reductions. Currently, the price of natural gas has been depressed due in some part to high levels of naturalgas inventory. Drilling for natural gas has been negatively impacted; however, drilling activity and our rental tools business has remainedactive with the focus on oil/liquids-rich shale plays.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARYDATA

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Board of Directors and StockholdersParker Drilling Company:

We have audited Parker Drilling Company’s internal control over financial reporting as of December 31, 2013, based on criteriaestablished in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the TreadwayCommission (COSO). Parker Drilling Company’s management is responsible for maintaining effective internal control over financialreporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanyingManagement’s Report on Internal Control over Financial Reporting in Item 9A. Our responsibility is to express an opinion on ParkerDrilling Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Thosestandards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financialreporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting,assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control basedon the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. Webelieve that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliabilityof financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accountingprinciples. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenanceof records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) providereasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generallyaccepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations ofmanagement and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorizedacquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projectionsof any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or procedures may deteriorate.

Parker Drilling Company acquired International Tubular Services Limited and certain of its affiliates (collectively, ITS) during 2013,and management excluded from its assessment of the effectiveness of Parker Drilling Company’s internal control over financial reporting asof December 31, 2013, ITS’s internal control over financial reporting. ITS represents approximately 11.0 percent of total assets as ofDecember 31, 2013 and approximately 10.0 percent and 37.0 percent of revenues and net income, respectively, included in the consolidatedfinancial statements of Parker Drilling Company as of and for the year ended December 31, 2013. Our audit of internal control overfinancial reporting of Parker Drilling Company also excluded an evaluation of the internal control over financial reporting of ITS.

In our opinion, Parker Drilling Company maintained, in all material respects, effective internal control over financial reporting as ofDecember 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of SponsoringOrganizations of the Treadway Commission (COSO).

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), theconsolidated balance sheets of Parker Drilling Company and subsidiaries as of December 31, 2013 and 2012, and the related consolidatedstatements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period endedDecember 31, 2013, and our report dated March 10, 2014 expressed an unqualified opinion on those consolidated financial statements.

/s/ KPMG LLP

Houston, TexasMarch 10, 2014

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMThe Board of Directors and StockholdersParker Drilling Company:

We have audited the accompanying consolidated balance sheets of Parker Drilling Company and subsidiaries as of December 31,2013 and 2012, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for eachof the years in the three‑year period ended December 31, 2013. In connection with our audits of the consolidated financial statements, wealso have audited financial statement Schedule II - Valuation and Qualifying Accounts. These consolidated financial statements andfinancial statement schedules are the responsibility of the Company’s management. Our responsibility is to express an opinion on theseconsolidated financial statements and financial statement schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are freeof material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financialstatements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well asevaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position ofParker Drilling Company and subsidiaries as of December 31, 2013 and 2012, and the results of their operations and their cash flows foreach of the years in the three‑year period ended December 31, 2013, in conformity with U.S. generally accepted accounting principles.Also in our opinion, the related financial statement schedule, when considered in relation to the basic consolidated financial statementstaken as a whole, presents fairly, in all material respects, the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), ParkerDrilling Company’s internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control -Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our reportdated March 10, 2014 expressed an unqualified opinion on the effectiveness of Parker Drilling Company’s internal control over financialreporting.

/s/ KPMG LLP

Houston, TexasMarch 10, 2014

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENT OF OPERATIONS

(Dollars in Thousands, Except Per Share Data)

Year Ended December 31,

2013 2012 2011Revenues $ 874,172 $ 677,761 $ 686,234Expenses:

Operating expenses 571,672 413,188 416,677Depreciation and amortization 134,053 113,017 112,136

705,725 526,205 528,813Total operating gross margin 168,447 151,556 157,421General and administration expense (68,025) (46,257) (31,567)Impairments and other charges — — (170,000)Provision for reduction in carrying value of certain assets (2,544) — (1,350)Gain on disposition of assets, net 3,994 1,974 3,659Total operating income (loss) 101,872 107,273 (41,837)Other income and (expense):

Interest expense (47,820) (33,542) (22,594)Interest income 2,450 153 256Loss on extinguishment of debt (5,218) (2,130) —Change in fair value of derivative positions 53 55 (110)Other 1,450 (832) (1,127)

Total other expense (49,085) (36,296) (23,575)Income (loss) before income taxes 52,787 70,977 (65,412)Income tax expense (benefit):

Current tax expense 12,909 18,042 33,608Deferred tax expense (benefit) 12,699 15,837 (48,375)

Total income tax expense (benefit) 25,608 33,879 (14,767)Net income (loss) 27,179 37,098 (50,645)Less: Net (loss) attributable to noncontrolling interest 164 (215) (194)Net income (loss) attributable to controlling interest $ 27,015 $ 37,313 $ (50,451)Basic earnings per share: $ 0.23 $ 0.32 $ (0.43)Diluted earnings per share: $ 0.22 $ 0.31 $ (0.43)Number of common shares used in computing earnings per share:

Basic 119,284,468 117,721,135 116,081,590Diluted 121,224,550 119,093,590 116,081,590

See accompanying notes to the consolidated financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)

Year Ended December 31,

2013 2012 2011

Comprehensive income: Net income (loss) $ 27,179 $ 37,098 $ (50,645)Other comprehensive gain, net of tax:

Currency translation difference on related borrowings (1,525) — —Currency translation difference on foreign currency net investments 3,051 — —

Total other comprehensive gain, net of tax: 1,526 — —Comprehensive income 28,705 37,098 (50,645)Comprehensive (income) loss attributable to noncontrolling interest 198 215 194Comprehensive income (loss) attributable to controlling interest $ 28,903 $ 37,313 $ (50,451)

See accompanying notes to the consolidated financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED BALANCE SHEET

(Dollars in Thousands)

December 31,

2013 2012ASSETS

Current assets: Cash and cash equivalents $ 148,689 $ 87,886Accounts and notes receivable, net of allowance for bad debts of $12,853 in 2013 and $8,117 in 2012 257,889 168,615Rig materials and supplies 41,781 29,422Deferred costs 13,682 1,089Deferred income taxes 9,940 8,742Other tax assets 24,079 33,524Other current assets 23,223 12,853

Total current assets 519,283 342,131Property, plant and equipment, at cost:

Drilling equipment 1,418,582 1,232,891Rental tools 395,626 337,874Buildings, land and improvements 49,518 38,736Other 61,273 57,185Construction in progress 82,381 190,445

2,007,380 1,857,131Less accumulated depreciation and amortization 1,136,024 1,063,934Property, plant and equipment, net 871,356 793,197

Other assets: Rig materials and supplies 10,221 12,930Debt issuance costs 14,208 8,863Deferred income taxes 102,420 95,295Other assets 17,268 3,317Total other assets 144,117 120,405

Total assets $ 1,534,756 $ 1,255,733LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities: Current portion of long-term debt $ 25,000 $ 10,000Accounts payable 90,033 62,090Accrued liabilities 84,853 75,656Accrued income taxes 7,266 4,120

Total current liabilities 207,152 151,866Long-term debt 628,781 469,205Other long-term liabilities 26,914 23,182Long-term deferred tax liability 38,767 20,847Commitments and contingencies (Note 15) — —

Stockholders’ equity: Preferred stock, $1 par value, 1,942,000 shares authorized, no shares outstanding — —Common stock, $0.16 2/3 par value, authorized 280,000,000 shares, issued and outstanding, 120,491,164

shares (118,968,396 shares in 2012) 20,075 19,818Capital in excess of par value 657,349 646,217Accumulated deficit (47,616) (74,631)Accumulated Other Comprehensive Income 1,888 —

Total controlling interest stockholders’ equity 631,696 591,404Noncontrolling interest 1,446 (771)

Total equity 633,142 590,633Total liabilities and stockholders’ equity $ 1,534,756 $ 1,255,733

See accompanying notes to the consolidated financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENT OF CASH FLOWS

(Dollars in Thousands)

Year Ended December 31, 2013 2012 2011CASH FLOWS FROM OPERATING ACTIVITIES:

Net income (loss) $ 27,179 $ 37,098 $ (50,645)Adjustments to reconcile net income (loss) to net cash provided by operatingactivities:

Depreciation and amortization 134,053 113,017 112,136Impairment of property, plant and equipment — — 170,000Loss on extinguishment of debt 5,218 2,130 —Gain on disposition of assets (3,994) (1,974) (3,659)Deferred tax expense (benefit) 12,699 15,837 (48,375)Provision for reduction in carrying value of certain assets 2,544 — 1,350Expenses not requiring cash 17,764 22,600 12,833Change in assets and liabilities:

Accounts and notes receivable (33,512) 15,241 (6,841)Rig materials and supplies 1,754 344 (913)Other current assets (11,715) (4,313) 63,816Accounts payable and accrued liabilities (286) (2,657) (24,908)Accrued income taxes 10,454 (6,102) 2,141Other assets (661) (1,522) (1,050)

Net cash provided by operating activities 161,497 189,699 225,885CASH FLOWS FROM INVESTING ACTIVITIES:

Capital expenditures (155,645) (191,543) (190,399)Proceeds from the sale of assets 8,218 3,937 5,535Acquisition of ITS, net of cash acquired (117,991) — —Proceeds from insurance claims — — 250Net cash used in investing activities (265,418) (187,606) (184,614)

CASH FLOWS FROM FINANCING ACTIVITIES: Proceeds from issuance of debt 350,000 130,000 50,000Proceeds from draw on revolver credit facility — 7,000 —Repayments of long-term debt (125,000) — —Repayments of senior notes — (125,000) —Repayments of term loan (50,000) (18,000) (21,000)Repayments of revolver — — (25,000)Payments of debt issuance costs (11,172) (4,859) (504)Payments of debt extinguishment costs — (555) —Proceeds from stock options exercised — — 183Excess tax benefit (expense) from stock-based compensation 896 (662) 1,488Net cash provided by (used in) financing activities 164,724 (12,076) 5,167

Net increase (decrease) in cash and cash equivalents 60,803 (9,983) 46,438Cash and cash equivalents at beginning of year 87,886 97,869 51,431Cash and cash equivalents at end of year 148,689 87,886 97,869Supplemental cash flow information:

Interest paid 42,236 37,405 32,785Income taxes paid 17,036 40,234 21,742

See accompanying notes to the consolidated financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED STATEMENT OF STOCKHOLDERS’ EQUITY

(Dollars and Shares in Thousands)

Shares Common

Stock Capital inExcess ofPar Value

AccumulatedDeficit

Accumulated OtherComprehensiveIncome (Loss)

TotalControlling

Stockholders’Equity

NoncontrollingInterest

TotalStockholders’

EquityBalances, December 31, 2010 116,369 $ 19,397 $ 630,409 $ (61,493 ) — $ 588,313 (247 ) $ 588,066

Activity in employees’ stock plans 692 111 (343 ) — — (232 ) — (232 )Excess tax benefit from stock basedcompensation — $ — $ 988 $ — — $ 988 — $ 988

Amortization of restricted stock plancompensation — — 5,988 — — 5,988 — 5,988Comprehensive Income:

Net income — — — (50,451 ) — (50,451 ) (194 ) (50,645 )Other, net — — — — (115 ) (115 )

Balances, December 31, 2011 117,061 $ 19,508 $ 637,042 $ (111,944 ) $ — $ 544,606 $ (556 ) $ 544,050Activity in employees’ stock plans 1,907 310 2,620 — — 2,930 — 2,930Excess tax deficit from stock optionsexercised — — (662 ) — — (662 ) — (662 )Amortization of restricted stock plancompensation — — 7,217 — — 7,217 — 7,217Comprehensive Income:

Net income — — — 37,313 — 37,313 (215 ) 37,098Balances, December 31, 2012 118,968 $ 19,818 $ 646,217 $ (74,631 ) $ — $ 591,404 $ (771 ) $ 590,633

Activity in employees’ stock plans 1,523 257 805 — — 1,062 — 1,062Excess tax benefit from stock optionsexercised — — 896 — — 896 — 896Amortization of restricted stock plancompensation — — 9,431 — — 9,431 — 9,431Fair value of acquired noncontrollinginterest — — — — — — 2,680 2,680Distributions to noncontrolling interest — — — — — — (265 ) (265 )Comprehensive Income:

Net income — — — 27,015 — 27,015 164 27,179Other comprehensive income (loss) — — — — 1,888 1,888 (362 ) 1,526

Balances, December 31, 2013 120,491 $ 20,075 $ 657,349 $ (47,616 ) $ 1,888 $ 631,696 $ 1,446 $ 633,142

See accompanying notes to the consolidated financial statements.

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NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Summary of Significant Accounting PoliciesNature of Operations — Parker Drilling, together with its subsidiaries, is an international provider of contract drilling and drilling-

related services and rental tools. We have operated in over 50 countries since beginning operations in 1934, making us among the mostgeographically experienced drilling contractors and rental tools providers in the world. We currently have operations in 24 countries, 10 ofwhich we entered through our acquisition in 2013 of International Tubular Services Limited and certain of its affiliates (collectively, ITS)and other related assets (the ITS Acquisition). We own and operate drilling rigs and drilling-related equipment and also perform drilling-related services, referred to as Operations & Maintenance (O&M) work, for customer-owned drilling rigs on a contracted basis. We haveextensive experience and expertise in drilling geologically difficult wells and in managing the logistical and technological challenges ofoperating in remote, harsh and ecologically sensitive areas. Our rental tools business supplies premium equipment to operators on land andoffshore in the U.S. and select international markets. We have significant knowledge of the equipment needs of drilling operators and thelogistical and product quality requirements of an effective rental tools supplier. We believe we are among the industry leaders in quality,health, safety and environmental practices.

Our business is currently comprised of five operating segments: Rental Tools, U.S. Barge Drilling, U.S. Drilling, InternationalDrilling, and Technical Services. Our rental tools business provides premium rental tools for land and offshore oil and natural gas drillingand workover and production applications. Tools we provide include drill pipe, heavy-weight drill pipe, tubing, high-torque connections,BOPs, drill collars, casing running systems, tools for fishing services and more. Our U.S. barge drilling business operates barge rigs thatdrill for oil and natural gas in the shallow waters in and along the inland waterways and coasts of Louisiana, Alabama, and Texas. Our U.S.drilling business primarily consists of two new-design arctic-class drilling rigs in Alaska intended to address the challenges presented bythe remote location, harsh climate and sensitive environment that characterize the Alaskan North Slope in addition to O&M work in supportof ExxonMobil’s Santa Ynez Unit offshore platform operations located in the Channel Islands region of California. Our internationaldrilling business includes operations related to Parker-owned and customer-owned rigs. Operations related to customer rigs includesoperations and maintenance and other project management services, such as labor, maintenance, and logistics for operators who own theirown drilling rigs, but choose Parker Drilling to operate the rigs for them. Our Technical services business includes engineering and relatedproject services during Front End Engineering Design (FEED), pre-FEED and concept development phases of customer-owned drillingfacility projects. During the EPCI phase we focus primarily on drilling systems engineering, procurement, commissioning and installationand we typically provide customer support during construction.

At December 31, 2013, our marketable rig fleet consisted of 13 barge drilling rigs and 23 land rigs located in the United States, LatinAmerica and the EMEA regions.

Consolidation — The consolidated financial statements include the accounts of the Company and subsidiaries in which we exercisecontrol or have a controlling financial interest, including entities, if any, in which the Company is allocated a majority of the entity’s lossesor returns, regardless of ownership percentage. If a subsidiary of Parker Drilling has a 50 percent interest in an entity but Parker Drilling’sinterest in the subsidiary or the entity does not meet the consolidation criteria described above, then that interest is accounted for under theequity method.

Noncontrolling Interest — We apply accounting standards related to noncontrolling interests for ownership interests in oursubsidiaries held by parties other than Parker Drilling. The entities that comprise the noncontrolling interest include Parker SMNG DrillingLimited Liability Company and Primorsky Drill Rig Services B.V. We report noncontrolling interest as equity on the consolidated balancesheets and report net income (loss) attributable to controlling interest and to noncontrolling interest separately on the consolidatedstatements of operations.

Reclassifications — Certain reclassifications have been made to prior period amounts to conform with the current periodpresentation. These reclassifications did not materially affect our consolidated financial results.

Revenue Recognition — Contract drilling revenues and expenses, comprised of daywork drilling contracts, call-outs against MSAsand engineering and related project service contracts, are recognized as services are performed and collection is reasonably assured. Forcertain contracts, we receive payments contractually designated for the mobilization of rigs and other drilling equipment. Mobilizationpayments received, and direct costs incurred for the mobilization, are deferred and recognized over the term of the related drilling contract;however, costs incurred to relocate rigs and other drilling equipment to areas in which a contract has not been secured are expensed asincurred. Reimbursements received for out-of-pocket expenses are recorded as both revenues and direct costs. For contracts that areterminated prior to the specified term, early termination payments received by us are recognized as revenues when all contractualrequirements are met. Revenues from rental activities are recognized ratably over the rental term which is generally less than six months.Construction contract revenues and costs are recognized on a percentage of completion basis utilizing the cost-to-cost method.

During 2013 the Company entered into a FEED contract including long-lead equipment procurement services accounted for underthe milestone method of revenue recognition. Milestone payments are based on achievement of specified

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procurement coordination and delivery events in regards to our customer's newly manufactured drilling rig. The quantity of specific long-lead items to be procured is spelled out in the contract and the payment terms are identified with each piece of equipment as well as eachspecific milestone. Management concluded that each of these payments, constitute substantive milestones. This conclusion was basedprimarily on the facts that (i) each triggering event represents a specific outcome that can be achieved only through successful performanceby the Company of one or more of its deliverables, (ii) achievement of each triggering event was subject to inherent risk and uncertaintyand would result in additional payments becoming due to the Company, (iii) each of the milestone payments is non-refundable, (iv)substantial effort is required to complete each milestone, (v) the amount of each milestone payment is reasonable in relation to the valuecreated in achieving the milestone, and (vi) the milestone payments relate solely to past performance.

Reimbursable Costs — The Company recognizes reimbursements received for out-of-pocket expenses incurred as revenues andaccounts for out-of-pocket expenses as direct operating costs. Such amounts totaled $69.7 million, $44.9 million, and $64.2 million duringthe years ended December 31, 2013, 2012, and 2011, respectively. Additionally, the Company typically receives a nominal handling fee,which is recognized as earned in revenues in our consolidated statement of operations.

Use of Estimates — The preparation of financial statements in accordance with U.S. GAAP requires us to make estimates andassumptions that affect our reported amounts of assets and liabilities, our disclosure of contingent assets and liabilities at the date of thefinancial statements, and our revenue and expenses during the periods reported. Estimates are typically used when accounting for certainsignificant items such as legal or contractual liability accruals, mobilization and deferred mobilization, revenue and cost accounting forprojects that follow the percentage of completion method, self-insured medical/dental plans, and other items requiring the use of estimates.Estimates are based on a number of variables which may include third party valuations, historical experience, where applicable, andassumptions that we believe are reasonable under the circumstances. Due to the inherent uncertainty involved with estimates, actual resultsmay differ from management estimates.

Purchase price allocation — We allocate the purchase price of an acquired business to its identifiable assets and liabilities based onestimated fair values at the transaction date. Transaction and integration costs associated with an acquisition are expensed as incurred. Theexcess of the purchase price over the amount allocated to the assets and liabilities, if any, is recorded as goodwill. We use all availableinformation to estimate fair values, including quoted market prices, the carrying value of acquired assets, and widely accepted valuationtechniques such as discounted cash flows. We typically engage third-party appraisal firms to assist in fair value determination ofinventories, identifiable intangible assets, and any other significant assets or liabilities. Judgments are made in determining the estimatedfair value assigned to each class of assets acquired and liabilities assumed, as well as asset lives, which can materially impact our results ofoperations.

Intangible Assets – We recorded $10.0 million and $0.2 million, upon the ITS Acquisition, to recognize the fair values of definite andindefinite lived intangible assets, respectively. Preliminary estimates of fair value of identifiable assets acquired and liabilities assumed inthe ITS Acquisition were based on management’s estimates, judgments and assumptions and are subject to change upon final valuation. Asof December 31, 2013, the fair value estimate of the definite lived and indefinite lived intangibles have been adjusted to $8.5 million andzero, respectively. Definite lived intangible assets recorded in connection with the ITS Acquisition primarily relate to trade names,customer relationships, and developed technology and will be amortized over a weighted average period of approximately 3 years. See Note2 - Acquisition of ITS for further discussion of the ITS Acquisition and preliminary fair value estimates.

Cash and Cash Equivalents — For purposes of the consolidated balance sheets and the consolidated statements of cash flows, theCompany considers cash equivalents to be highly liquid debt instruments that have a remaining maturity of three months or less at the dateof purchase.

Accounts Receivable and Allowance for Doubtful Accounts — Trade accounts receivable are recorded at the invoice amount andtypically do not bear interest. The allowance for doubtful accounts is estimated for losses that may occur resulting from disputed amountsand the inability of our customers to pay amounts owed. We estimate the allowance based on historical write-off experience andinformation about specific customers. We review individually, for collectability, all balances over 90 days past due as well as balances duefrom any customer with respect to which we have information leading us to believe that a risk exist for potential collection.

Account balances are charged off against the allowance when we believe it is probable the receivable will not be recovered. We donot have any off-balance-sheet credit exposure related to customers.

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December 31,

2013 2012 (Dollars in Thousands)Trade $ 270,498 $ 176,082Notes receivable 244 650Allowance for doubtful accounts(1) (12,853) (8,117)

Total accounts and notes receivable, net of allowance for bad debt $ 257,889 $ 168,615

(1) Additional information on the allowance for doubtful accounts for the years ended December 31, 2013, 2012 and 2011 is reported onSchedule II — Valuation and Qualifying Accounts.Property, Plant and Equipment — Property, plant and equipment is carried at cost. Maintenance and repair costs are expensed as

incurred. The cost of upgrades and replacements is capitalized. The Company capitalizes software developed or obtained for internal use.Accordingly, the cost of third-party software, as well as the cost of third-party and internal personnel that are directly involved inapplication development activities, are capitalized during the application development phase of new software systems projects. Costs duringthe preliminary project stage and post-implementation stage of new software systems projects, including data conversion and training costs,are expensed as incurred. We account for depreciation of property, plant and equipment on the straight line method over the estimateduseful lives of the assets after provision for salvage value. Depreciation, for tax purposes, utilizes several methods of accelerateddepreciation. Depreciable lives for different categories of property, plant and equipment are as follows:

Land drilling equipment 3 to 20 yearsBarge drilling equipment 3 to 20 yearsDrill pipe, rental tools and other 4 to 10 yearsBuildings and improvements 5 to 30 years

Impairment — We review the carrying amounts of long-lived assets for potential impairment annually, typically during the fourthquarter, or when events occur or circumstances change that indicate the carrying value of such assets may not be recoverable. Wedetermine recoverability by evaluating the undiscounted estimated future net cash flows. When impairment is indicated, we measure theimpairment as the amount by which the assets’ carrying value exceeds its fair value. Management considers a number of factors such asestimated future cash flows from the assets, appraisals and current market value analysis in determining fair value. Assets are written downto fair value if the final estimate of current fair value is below the net carrying value.

Capitalized Interest — Interest from external borrowings is capitalized on major projects until the assets are ready for their intendeduse. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful lives of the assets in the same manneras the underlying assets. Capitalized interest costs reduce net interest expense in the consolidated statements of operations. During 2013,2012 and 2011, capitalized interest costs were $2.4 million, $10.2 million and $19.3 million, respectively.

Assets held for sale — We classify an asset as held for sale when the facts and circumstances meet the criteria for such classification,including the following: (a) we have committed to a plan to sell the asset, (b) the asset is available for immediate sale, (c) we have initiatedactions to complete the sale, including locating a buyer, (d) the sale is expected to be completed within one year, (e) the asset is beingactively marketed at a price that is reasonable relative to its fair value, and (f) the plan to sell is unlikely to be subject to significant changesor termination.

Rig Materials and Supplies — Because our international drilling generally occurs in remote locations, making timely outside deliveryof spare parts uncertain, a complement of parts and supplies is maintained either at the drilling site or in warehouses close to the operation.During periods of high rig utilization, these parts are generally consumed and replenished within a one-year period. During a period oflower rig utilization in a particular location, the parts, like the related idle rigs, are generally not transferred to other international locationsuntil new contracts are obtained because of the significant transportation costs that would result from such transfers. We classify those partswhich are not expected to be utilized in the following year as long-term assets. Additionally, our international rental tools business holdsmachine shop consumables and steel stock for manufacture in our machine shops and inspection and repair shops. Rig materials andsupplies are valued at the lower of cost or market value.

Deferred Costs — We defer costs related to rig mobilization and amortize such costs over the term of the related contract. The coststo be amortized within twelve months are classified as current.

Debt Issuance Costs — We typically defer costs associated with issuance of indebtedness, and amortize those costs over the term ofthe related debt using the effective interest method.

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Income Taxes — Income taxes are accounted for under the asset and liability method and have been provided based upon tax lawsand rates in effect in the countries in which operations are conducted and income is earned. There is little or no expected relationshipbetween the provision for or benefit from income taxes and income or loss before income taxes as the countries in which we operate havetaxation regimes that vary not only with respect to nominal rate, but also in terms of the availability of deductions, credits, and otherbenefits. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financialstatement carrying amounts of existing assets and liabilities and their respective tax bases and operating loss and tax creditcarryforwards. Deferred tax assets and liabilities are measured using enacted tax rates in effect for the year in which the temporarydifferences are expected to be recovered or settled and the effect of changes in tax rates is recognized in income in the period in which thechange is enacted. Accordingly, the impact of the Mexican tax reform, which was enacted October 31, 2013, has been recognized in2013. The Company recognizes the effect of income tax positions only if those positions are more likely than not to besustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized andchanges in recognition or measurement are reflected in the period in which the change in judgment occurs.

Earnings (Loss) Per Share (EPS) — Basic earnings (loss) per share is computed by dividing net income by the weighted averagenumber of common shares outstanding during the period. The effects of dilutive securities, stock options, unvested restricted stock andconvertible debt are included in the diluted EPS calculation, when applicable.

Concentrations of Credit Risk — Financial instruments, that potentially subject the Company to concentrations of credit risk consistprimarily of trade receivables with a variety of national and international oil and natural gas companies. We generally do not requirecollateral on our trade receivables.

At December 31, 2013 and 2012, we had deposits in domestic banks in excess of federally insured limits of approximately $104.3million and $12.2 million, respectively. The increase is primarily because as of January 1, 2013, all regular checking account deposits areonly guaranteed up to $250,000 at each institution while prior to January 1, 2013, all regular checking account deposits were guaranteed,except investments. In addition, we had deposits in foreign banks, which were not insured at December 31, 2013 and 2012 of $50.1 millionand $34.5 million, respectively.

Our customer base primarily consists of major, independent and national oil and natural gas companies and integrated serviceproviders. We depend on a limited number of significant customers. Our largest customer, Exxon Neftegas Limited constituted 15.6percent of our revenues for 2013.

Fair value measurements— For purposes of recording fair value adjustments for certain financial and non-financial assets andliabilities, and determining fair value disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfera liability in an orderly transaction between market participants in the principal market for the asset or liability. Our valuation techniquerequires inputs that we categorize using a three-level hierarchy, from highest to lowest level of observable inputs, as follows: (1) unadjustedquoted prices for identical assets or liabilities in active markets (Level 1), (2) direct or indirect observable inputs, including quoted prices orother market data, for similar assets or liabilities in active markets or identical assets or liabilities in less active markets (Level 2) and(3) unobservable inputs that require significant judgment for which there is little or no market data (Level 3). When multiple input levelsare required for a valuation, we categorize the entire fair value measurement according to the lowest level of input that is significant to themeasurement even though we may have also utilized significant inputs that are more readily observable.

Derivative Financial Instruments — We periodically use derivative instruments to manage risks associated with changes inassociated interest rate fluctuations in connection with our Secured Credit Agreement (see Note 9, Derivative Financial Instruments ).These derivative instruments, which consist of variable-to-fixed interest rate swaps, are not designated as hedges. Accordingly, the changein the fair value of the interest rate swaps is recognized in earnings at each reporting period.

Foreign Currency — In our international rental tool business, for certain subsidiaries and branches outside the U.S., the localcurrency is the functional currency. The financial statements of these subsidiaries and branches are translated into U.S. dollars as follows:(i) assets and liabilities at month-end exchange rates; (ii) income, expenses and cash flows at monthly average exchange rates or exchangerates in effect on the date of the transaction; and (iii) stockholders’ equity at historical exchange rates. For those subsidiaries where thelocal currency is the functional currency, the resulting translation adjustment is recorded as a component of accumulated other elements ofcomprehensive income (loss) in the accompanying consolidated balance sheets.

Stock-Based Compensation — Under our long term incentive plans, we grant restricted stock awards (RSA), restricted stock units(RSU) and performance-based award units (PAU). Our RSUs and RSAs are service-based awards and compensation expense is recognizedratably over the applicable vesting period, which is typically three years. The grant-date fair value of nonvested RSAs and RSUs isdetermined based on the closing trading price of the company’s shares on the grant date. Our RSAs and RSUs are settled in stock uponvesting. Share-based compensation expense is recognized, net of an estimated forfeiture rate, which is based on historical experience andadjusted, if necessary, in subsequent periods based on actual forfeitures. Our PAU awards contain market conditions which are based on ourperformance against our peers with regard to

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relative total shareholder return (TSR) and absolute and relative return on capital employed (ROCE). The effect of the market condition isreflected in the grant-date fair value of the award using a lattice model for valuation. PAUs can be settled in cash or stock, or a combinationof cash and stock. We evaluate the terms of each PAU award to determine if the award should be accounted for as equity or a liability underthe stock compensation rules of U.S. GAAP. Compensation costs for PAUs is recognized ratably over the service period.

We recognize share-based compensation expense in the same financial statement line item as cash compensation paid to therespective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a financing cash flow.

Note 2 — Acquisition of ITS

On April 22, 2013 we acquired International Tubular Services Limited and certain of its affiliates (collectively, ITS) and other relatedassets (the ITS Acquisition) for an initial purchase price of $101.0 million paid at the closing of the ITS Acquisition. An additional $24.0million was deposited into an escrow account, which will either be paid to the seller or to us, as the case may be, in accordance with theAgreement. As of December 31, 2013 $5.0 million of escrow funds has been released to the seller. The ITS Acquisition closedsimultaneously with the execution of the agreement on April 22, 2013.

Fair value of Consideration Transferred

The following details the fair value of the consideration transferred to effect the ITS Acquisition (dollars in thousands).

Cash paid to, or on behalf of, ITS and its equity holders $ 101,000Cash deposited in escrow 19,000Fair value of contingent consideration deposited in escrow for assets not acquired (1) 5,000Total fair value of the consideration transferred $ 125,000

(1) Based on the terms of the acquisition agreement, $5.0 million of the $24.0 million in escrow to be paid to the seller iscontingent upon certain future liabilities that could become due by ITS in certain jurisdictions. Any payments in relation to theseliabilities will be deducted from the $5.0 million escrow amount and the net balance of the escrow will be paid to the seller. Weestimate that the entire $5.0 million in escrow will be paid to the seller, and therefore, the estimated fair value of the consideration inescrow related to these liabilities is $5.0 million. We do not expect to receive any amount back from escrow, and therefore did notrecord a receivable from the escrow. Any changes to the fair value of the contingent consideration in the future of less than $5.0million will result in recording a receivable from escrow. The receivable will be recorded at fair value. As of December 31, 2013, thefair value of the receivable is $0.0 million.

Preliminary Allocation of Consideration Transferred to Net Assets Acquired

Preliminary estimates of fair value of identifiable assets acquired and liabilities assumed in the ITS Acquisition were based onmanagement’s estimates, judgments and assumptions and are subject to change upon final valuation. As of December 31, 2013, the fairvalue estimate of certain identifiable assets acquired and liabilities assumed has been adjusted. These estimates, judgments andassumptions are subject to change upon final valuation and should be treated as preliminary values. Management estimated that the fairvalue of the net assets acquired less noncontrolling interest equals consideration paid. Therefore, there was no goodwill recorded.

The final allocation of consideration will include changes in (1) amounts deposited in escrow, (2) estimated fair values ofproperty and equipment, (3) allocations to intangible assets and liabilities, (4) changes in contingent consideration, and (5) other assetsand liabilities. These amounts will be finalized as soon as possible, but no later than one year from the acquisition date.

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April 22, 2013 (In thousands)

Cash and cash equivalents $ 7,009Accounts and notes receivable, net (1) 50,043Other current assets 1,803Accounts payable and accrued liabilities (39,156 )Accrued income taxes (1,251 )

Working capital excluding rig materials and supplies 18,448Rig materials and supplies 11,514Property, plant and equipment, net (2) 73,863Investment in joint venture 4,134Other noncurrent assets 2,818

Total tangible assets 110,777Deferred income tax assets - current 222Deferred income tax assets - noncurrent (3) 11,249Intangible assets (4) 8,500

Total assets acquired 130,748Other long-term liabilities (211 )Long-term deferred tax liability (2,856 )

Net assets acquired 127,681Less: Noncontrolling interest (5) (2,681 )Total consideration transferred $ 125,000

(1) Gross contractual amounts receivable totaled $55.9 million as of the acquisition date.

(2) We recorded an adjustment of $40.2 million to reduce the historical carrying value of the acquired property, plant andequipment to its estimated fair value.

(3) In connection with the ITS Acquisition, we recorded a $5.0 million adjustment to increase deferred income tax assetsprimarily related to the differences between acquisition date estimated fair value and tax basis of acquired property, plant andequipment.

(4) We recorded $8.5 million to reflect the estimated fair value of definite lived intangible assets recognized in connection withthe ITS Acquisition. Our depreciation and amortization expense will reflect this valuation adjustment as the definite lived intangibleassets are amortized in future periods. Definite lived intangible assets recorded in connection with the ITS Acquisition, which primarilyrelate to trade names, customer relationships, and developed technology will be amortized over a weighted average period ofapproximately 3.4 years.

(5) We recorded an adjustment of $1.0 million to write-down the noncontrolling interest to its estimated fair value. Theestimated fair value of the noncontrolling interest was calculated as a percentage of the net assets acquired related to certainsubsidiaries in which ITS holds less than a 100 percent controlling interest. The fair value of the net assets of these subsidiaries wasprimarily based on the income approach valuation model.

Acquisition Related Costs

Acquisition-related transaction costs consisted of various advisory, compliance, legal, accounting, valuation and otherprofessional or consulting fees totaled approximately $22.5 million for the year ended December 31, 2013. The costs were expensed asincurred and are included in general and administrative expense in our consolidated statement of operations. Debt issuance costs of$5.4 million associated with our $125 million term loan, fully funded by Goldman Sachs Bank USA as Sole Lead Arranger andAdministrative Agent (the Goldman Term Loan) issued on April 18, 2013 were initially deferred to be amortized to interest expenseover the life of the term loan. However, the Goldman Term Loan was repaid on July 30, 2013 with net proceeds from the issuance of$225.0 million aggregate principal amount of

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7.50% Senior Notes due August 1, 2020 (7.50% Notes) (see Note 8 - Long-Term Debt, for further discussion) and the unamortizeddeferred costs of $5.2 million were expensed during the 2013 third quarter.

Supplemental Pro forma Results

ITS’ results of operations have been included in our financial statements for periods subsequent to April 22, 2013, the effectivedate of the ITS Acquisition. ITS contributed revenues of $88.0 million and net income of approximately $10.0 million to ParkerDrilling for the period from the closing of the ITS Acquisition through December 31, 2013.

The following unaudited supplemental pro forma results present consolidated information for the years ended December 31,2013 and 2012 as if the ITS Acquisition had been completed on January 1, 2012. The pro forma results have been calculated afterapplying our accounting policies and include, among others, (i) the amortization associated with the fair value of the acquiredintangible assets, (ii) interest expense associated with the Goldman Term Loan and (iii) the impact of certain fair value adjustmentssuch as a decrease in depreciation expense related to the write-down in property, plant and equipment. The pro forma results do notinclude any potential synergies, non-recurring charges which result directly from the ITS Acquisition, cost savings or other expectedbenefits of the ITS Acquisition. The pro forma financial information does not necessarily represent what would have occurred if thetransaction had taken place at the beginning of the period presented and should not be taken as representative of our futureconsolidated results of operations. We have not concluded our integration work. Accordingly, this pro forma information does notinclude all costs related to the integration nor the benefits we expect to realize from operating synergies.

Year ended December 31, (unaudited) 2013 2012 (Dollars in thousands, except per share data)

Revenue $ 914,992 $ 794,640Net income $ 45,785 $ (14,117 )Net income attributable to Parker Drilling $ 45,391 $ (13,981 )Earnings per share - basic $ 0.38 $ (0.12 )Earnings per share - diluted $ 0.37 $ (0.12 )

Basic number of shares 119,284,468 117,721,135Diluted number of shares 121,224,550 119,093,590

Note 3 — Accumulated Other Comprehensive Income

Accumulated other comprehensive loss consisted of the following:

Foreign Currency Items (in thousands)December 31, 2012 $ —Current period other comprehensive income 1,888December 31, 2013 $ 1,888

No amounts were reclassified out of accumulated other comprehensive income for the year ended December 31, 2013.

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Note 4 — Asset ImpairmentAsset ImpairmentDuring the fourth quarter of 2011, we evaluated the present value of the future cash flows related to our arctic-class drilling rigs in

accordance with the U.S. GAAP guidance for impairment or disposal of long-lived assets. The evaluation was performed as a result of thedelay in completion of the rigs to modify the rigs to meet their design and functional requirements and an increase in the cost of the rigs.The need for the modifications was determined as a result of comprehensive safety, technical and operational reviews duringcommissioning activities of these prototype drilling rigs. The modification work extended the commissioning activities and increased therigs’ total costs. At the time of the impairment evaluation, the two rigs’ cost at completion was estimated to be $385 million, whichincluded capitalized interest estimates of approximately $50.7 million. This cost exceeded the estimated fair value of the rigs based on theirprojected cash flows. Based on this evaluation, the Company determined that the long-lived assets with a carrying amount of $339.5million as of December 31, 2011, were no longer recoverable and were in fact impaired and recorded a charge in the 2011 fourth quarter of$170.0 million ($109.1 million, net of taxes) to reflect their estimated fair value of $169.5 million. Fair value was based on expected futurecash flows using Level 3 inputs under the fair value measurement requirements. The cash flows are those expected to be generated by ourassets, discounted at the 10 percent rate of interest. In December 2012 we commenced drilling operations with the first arctic-class drillingrig. The second rig completed client acceptance testing and began drilling in February 2013. The rigs are reported as part of the U.S.Drilling segment.

Provision for Reduction in Carrying Value of an AssetDuring the 2013 fourth quarter, for two rigs previously reported as assets held for sale as of December 31, 2012, management

concluded that facts and circumstances no longer support the expectation that a sale would be consummated within a reasonable timeperiod. As a result, we reclassified these assets back to assets held and used in accordance with generally accepted accounting principles.Concurrently, we performed an impairment analysis of the two rigs and determined the fair value was less than the carrying amount beforethe assets were classified as held for sale, adjusted for any depreciation expense that would have been recognized had the assets beencontinuously classified as held and used. Therefore, during the 2013 fourth quarter we recorded a non-cash charge of $1.9 million to reflectthe rigs current estimated fair value. Additionally, during the 2013 fourth quarter a sales agreement was terminated for three additional rigswhich were previously expected to be sold prior to December 31, 2013. Upon termination of the sales agreement we performed a fair valueanalysis of the rigs and concluded for one rig, the carrying value of the rig exceeded fair value. Therefore, during the 2013 fourth quarterwe recorded a non-cash charge of $0.6 million. Fair value was based on expected future cash flows using Level 3 inputs in accordance withfair value measurement requirements. The two rigs are reported as part of the International Drilling segment.

In 2011, we recognized a charge of $1.4 million related to a final settlement of a bankruptcy proceeding.

Note 5 — Disposition of AssetsDuring the 2013 fourth quarter, we sold two rigs located in New Zealand, including rig related inventory, property and leasehold

improvements. The assets had a carrying value at the time of sale of $2.3 million and were sold for proceeds of $3.2 million resulting in again of approximately $0.9 million. The assets were part of our international drilling rig fleet. During the 2013 fourth quarter we alsocompleted the sale of a building located in Tulsa, OK. As a result of the completed sale, we recognized proceeds of $0.8 million and $0.1million gain on the sale. Additionally, during the 2013 third quarter we sold a barge rig located in Mexico with carrying value at the timeof sale of $0.3 million for proceeds of $0.5 million, resulting in a $0.2 million gain. The barge rig was part of our Latin America rig fleetand has historically been included in the international drilling segment.

In December 2012, we sold a 33 year old posted barge drilling rig for proceeds of $0.2 million, resulting in a $0.5 million loss. Therewere no individually significant asset dispositions in 2011.

In addition, during the normal course of operations, we periodically sell equipment deemed to be excess, obsolete, or not currentlyrequired for operations.

Note 6 — Assets Held for SaleWe had no assets classified as assets held for sale as of December 31, 2013. During 2013, for five rigs previously reported as assets

held for sale, management concluded that facts and circumstances no longer support the expectation that a sale would be consummatedwithin a reasonable time period. During the 2013 second quarter, we reclassified three rigs from assets held for sale to assets held and usedand inventory. We initially classified the three rigs as assets held for sale as of December 31, 2010. We performed an analysis of the fairvalue of the three rigs and determined the rigs' carrying amount was less than fair value; therefore, the rigs were reclassified at theircarrying amount at the time the assets were classified asheld for sale, adjusted for depreciation expense that would have been recognized had the assets been continuously classified as

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held and used. The amount of additional depreciation recorded during the 2013 second quarter to place the assets in held and usedcategorization was $0.7 million.

Additionally, during the 2013 fourth quarter we reclassified two rigs from assets held for sale to assets held and used and inventory.We initially classified these rigs as held for sale as of September 30, 2012. We performed an analysis of the fair value of the two rigs anddetermined the fair value was less than the carrying amount before the assets were classified as held for sale, adjusted for any depreciationexpense that would have been recognized had the assets been continuously classified as held and used. Therefore, during the 2013 fourthquarter we recorded a non-cash charge of $1.9 million to reflect the rigs current estimated fair value.

We have adjusted the Assets held for sale, Inventory, and Property, plant and equipment balances for the year ended December 31,2012 from what was reported in our December 31, 2012 Form 10-K, to reflect the reclassification of these assets.

Note 7 — Income TaxesIncome (loss) before income taxes is summarized below:

Year Ended December 31,

2013 2012 2011 (Dollars in Thousands)United States $ 32,136 $ 52,422 $ (61,434)Foreign 20,651 18,555 (3,978) $ 52,787 $ 70,977 $ (65,412)

Income tax expense (benefit) is summarized as follows:

Year Ended December 31,

2013 2012 2011 (Dollars in Thousands)Current:

United States: Federal $ (3,658) $ 7,791 $ 17,168State 1,968 733 1,264

Foreign 14,599 9,518 15,176Deferred:

United States: Federal 10,720 15,612 (46,694)State 2,820 4,296 1,864

Foreign (841) (4,071) (3,545) $ 25,608 $ 33,879 $ (14,767)

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Total income tax expense differs from the amount computed by multiplying income before income taxes by the U.S. federal incometax statutory rate. The reasons for this difference are as follows:

Year Ended December 31,

2013 2012 2011 (Dollars in thousands)

Amount % of Pre-Tax

Income Amount % of Pre-Tax

Income Amount % of Pre-Tax

IncomeComputed Expected Tax Expense $ 18,476 35 % $ 24,842 35 % $ (22,894) 35 %Foreign Taxes 12,470 24 % 13,171 19 % 11,752 (17)%Tax Effect Different FromStatutory Rates (8,920) (17)% (8,080) (11)% (1,571) 2 %State Taxes, net of federal benefit 4,099 8 % 4,757 7 % 2,689 (4)%Foreign Tax Credits (1,484) (3)% (1,867) (3)% (14,595) 22 %Kazakhstan Tax Settlement — — % — — % (536) 1 %Change in Valuation Allowance 1,975 4 % (1,662) (2)% 2,542 (4)%Uncertain Tax Positions 2,472 5 % (6,642) (9)% 3,647 (6)%Permanent Differences 4,005 7 % 5,477 8 % 6,356 (10)%Prior Year Return to ProvisionAdjustments (6,268) (12)% 4,057 5 % 4,156 (6)%Other (1,217) (2)% (174) (1)% (829) 1 %Unremitted Foreign Earnings-Current Year Adjustment — — % — — % (5,484) 8 %Actual Tax Expense $ 25,608 49 % $ 33,879 48 % $ (14,767) 22 %

The balances for the years ended December 31, 2012 and 2011 have been adjusted to reflect reclassifications of $1.3 million and$5.6 million, respectively, between foreign taxes and, primarily, prior year return to provision adjustments and amendments and other.Management concluded based on the facts and circumstances during 2013 the adjustments are closely related to items included in foreigntaxes.

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The components of the Company’s deferred tax assets and liabilities as of December 31, 2013 and 2012 are shown below:

December 31,

2013 2012 (Dollars in Thousands)Deferred tax assets

Current deferred tax assets: Reserves established against realization of certain assets $ 1,504 $ 1,634Accruals not currently deductible for tax purposes 7,223 6,747Other state deferred tax asset, net 990 361Foreign Local Office 223 —Gross current deferred tax assets 9,940 8,742Current deferred tax valuation allowance — —

Net current deferred tax assets 9,940 8,742Non-current deferred tax assets:

Federal net operating loss carryforwards — —State net operating loss carryforwards 864 3,095Other state deferred tax asset, net 1,909 914Foreign Tax Credits 27,462 25,977FIN 48 8,317 8,015Foreign tax 18,499 5,838Asset Impairment 48,743 56,190Accruals not currently deductible for tax purposes 1,017 —Deferred compensation 2,436 —Other — 71Gross long-term deferred tax assets 109,247 100,100

Valuation Allowance (6,827) (4,805)Net non-current deferred tax assets, net of valuation allowance

102,420 95,295Net deferred tax assets 112,360 104,037

Deferred tax liabilities: Non-current deferred tax liabilities:

Property, Plant and equipment (32,505) (19,139)Accruals — (1,066)Foreign tax local (1,440) —Deferred Compensation — 2,001Other state deferred tax liability, net (4,819) (2,643)Other (3) —

Gross non-current deferred tax liabilities (38,767) (20,847)Net deferred tax asset $ 73,593 $ 83,190

As part of the process of preparing the consolidated financial statements, the Company is required to determine its provision forincome taxes. This process involves estimating the annual effective tax rate and the nature and measurements of temporary and permanentdifferences resulting from differing treatment of items for tax and accounting purposes. These differences and the operating loss and taxcredit carryforwards result in deferred tax assets and liabilities. In assessing the realizability of deferred tax assets, management considerswhether it is more likely than not that all or a portion of the deferred tax assets will not be realized. The ultimate realization of deferred taxassets is dependent upon the generation of future taxable income of appropriate character in each taxing jurisdiction during the periods inwhich those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (includingthe impact of available carryback and carryforward periods), projected future taxable income, and tax planning strategies in making thisassessment. To the extent the Company believes that it does not meet the test that recovery is more likely than not, it establishes a valuationallowance. To the extent that the Company establishes a valuation allowance or changes this allowance in a period, it adjusts the taxprovision or tax benefit in the consolidated statement of operations. We use our judgment in determining provisions or benefits for incometaxes, and any valuation allowance recorded against previously established deferred tax assets. Based upon the

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factors considered by management in assessing the realizability of the deferred tax assets, management believes it is more likely than notthat the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31,2013. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxableincome during the carryforward period are reduced.

On September 13, 2013, the U.S. Treasury Department and the Internal Revenue Service issued final regulations that address costsincurred in acquiring, producing, or improving tangible property (the “tangible property regulations”). The tangible property regulationsare generally effective for tax years beginning on or after January 1, 2014. The tangible property regulations required the Company tomake additional tax accounting method changes as of January 1, 2014; however, the impact of these changes has not been material to theCompany’s consolidated financial position, its results of operations, or both.

The 2013 results include income tax benefits of $3.3 million related to the enacted Mexican tax reform as applied to the expectedfuture utilization of deferred tax assets and liabilities and $20.9 million for depreciation and amortization relating to our arctic-class drillingrigs in Alaska. In addition, we increased our valuation allowance by $2.0 million primarily related to foreign net operating losses.

The 2012 results include income tax expenses of $1.7 million related to the effective settlement of our US Federal Internal RevenueService examination for the 2006 through 2010 periods and $7.7 million for depreciation and amortization relating to our arctic-classdrilling rigs in Alaska. In addition, we decreased our valuation allowance by $1.7 million primarily related to foreign NOLs.

The 2011 results include an income tax benefit of $60.9 million (federal and state combined) related to the $170.0 million non-cashpretax impairment charge relating to our arctic-class drilling rigs in Alaska. In addition, we increased our valuation allowance by $2.5million primarily related to foreign NOLs.

A reconciliation of the beginning and ending amount of unrecognized tax benefits is as follows:

In ThousandsBalance at January 1, 2013 $ (10,030)

Additions based on tax positions taken during a prior period (3,245)Reductions related to settlement of tax matters 1,066Reductions related to a lapse of applicable statute of limitations —

Balance at December 31, 2013 $ (12,209)

In many cases, our uncertain tax positions are related to tax years that remain subject to examination by tax authorities. The followingdescribes the open tax years, by major tax jurisdiction, as of December 31, 2013:

Colombia 2008-presentKazakhstan 2007-presentMexico 2008-presentPapua New Guinea 2010-presentRussia 2010-presentUnited States — Federal 2011-presentUnited Kingdom 2010-present

At December 31, 2013, we had a liability for unrecognized tax benefits of $12.2 million ($5.4 million of which, if recognized, wouldfavorably impact our effective tax rate).

The Company recognized interest and penalties related to uncertain tax positions in income tax expense. As of December 31, 2013and December 31, 2012 we had approximately $7.9 million and $7.0 million of accrued interest and penalties related to uncertain taxpositions, respectively. We recognized an increase of $0.9 million of interest and no penalties on unrecognized tax benefits for the yearended December 31, 2013.

As of December 31, 2013, the Company has permanently reinvested accumulated undistributed earnings of foreign subsidiaries and,therefore, has not recorded a deferred tax liability related to subject earnings. Upon distribution of additional earnings in the form ofdividends or otherwise, we would likely be subject to US income taxes and foreign withholding taxes. It is not practicable to determineprecisely the amount of taxes that may be payable on the eventual remittance of these earnings because of the application of US foreign taxcredits. While we currently claim foreign tax credits, we may not be in a credit position if and when future remittances of foreign earningsoccur, or the limitation imposed by the Internal Revenue Code and regulations thereunder may not allow the credits to be utilized duringthe applicable carryback and carryforward periods.

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Note 8 — Long-Term DebtThe following table illustrates the Company’s current debt portfolio as of December 31, 2013 and December 31, 2012:

December 31,

2013 2012 (Dollars in Thousands)7.50% Senior Notes, due August 2020 $ 225,000 $ —9.125% Senior Notes, due April 2018 428,781 429,205Term Note - Effective interest rate of 3.21 percent at December 31, 2012 — 50,000Total debt 653,781 479,205Less current portion 25,000 10,000Total long-term debt $ 628,781 $ 469,205

As of December 31, 2013, we have no debt maturities prior to 2018. However, we have classified $25.0 million of 9.125% SeniorNotes (9.125% Notes) due April 2018, as current debt as management intends to repay this debt prior to maturity. The aggregate maturitiesof long-term debt, including unamortized premiums of $3.8 million, for 2018 and thereafter is $628.8 million. Subsequent to December 31,2013, we issued $360.0 million aggregate principal amount of 6.75% Senior Notes due 2022 (6.75% Notes). Net proceeds from the 6.75%Notes offering plus a $40.0 million draw on the Secured Credit Agreement and cash on hand, were utilized to redeem $416.2 millionaggregate principal amount of our outstanding 9.125% Notes. After payment for the tendered notes, $8.8 million aggregate principalamount of our 9.125% Notes remains outstanding. At December 31, 2013 management had the ability and intent to refinance the 9.125%Notes. With the issuance of the 6.75% Notes and the $40.0 million borrowing on the Secured Credit Agreement, we refinanced $400.0million of our long-term debt, which remains classified as long-term debt as of December 31, 2013. The remaining $25.0 million of9.125% Notes is classified as current debt as management intends to repay this portion of the debt prior to maturity. See Note 21 -Subsequent Events, for further discussion.

7.50% Senior Notes, due August 2020On July 30, 2013, we issued $225.0 million aggregate principal amount of 7.50% Notes pursuant to an Indenture between the

Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 7.50% Notes offering wereprimarily used to repay the $125.0 million aggregate principal amount of the Goldman Term Loan, to repay $45.0 million of Term Loanborrowings under our Secured Credit Agreement and for general corporate purposes.

The 7.50% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing andfuture senior unsecured indebtedness. The 7.50% Notes are jointly and severally guaranteed by all of our subsidiaries that guaranteeindebtedness under our Secured Credit Agreement Interest on the 7.50% Notes is payable on February 1 and August 1 of each year,beginning February 1, 2014. Debt issuance costs related to the 7.50% Notes were $5.3 million ($5.1 million, net of amortization as ofDecember 31, 2013) and will be amortized over the term of the notes using the effective interest rate method.

At any time prior to August 1, 2016, we may redeem up to 35 percent of the aggregate principal amount of the 7.50% Notes at aredemption price of 107.50 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cashproceeds of certain equity offerings by us. On and after August 1, 2016, we may redeem all or a part of the 7.50% Notes upon appropriatenotice, at a redemption price of 103.750 percent of the principal amount, and at redemption prices decreasing each year thereafter to parbeginning August 1, 2018. If we experience certain changes in control, we must offer to repurchase the 7.50% Notes at 101.0 percent of theaggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make otherdistributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur orguarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or otherpayment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and(x) engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events asEvents of Default. These covenants are subject to a number of important exceptions and qualifications.

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9.125% Senior Notes, due April 2018On March 22, 2010, we issued $300.0 million aggregate principal amount of 9.125% Notes pursuant to an Indenture between the

Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 9.125% Notes offering wereprimarily used to redeem the $225.0 million aggregate principal amount of our 9.625% Senior Notes due 2013 and to repay $42.0 millionof borrowings under our Secured Credit Agreement.

On April 25, 2012, we issued an additional $125.0 million aggregate principal amount of 9.125% Notes under the same indenture at aprice of 104.0 percent of par, resulting in gross proceeds of $130.0 million. Net proceeds from the offering were utilized to refinance$125.0 million aggregate principal amount of the 2.125% Convertible Notes due July 2012. We repurchased $122.9 million aggregateprincipal amount of the 2.125% Convertible Notes tendered pursuant to a tender offer on May 9, 2012 and paid off the remaining $2.1million at their stated maturity on July 15, 2012.

The 9.125% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing andfuture senior unsecured indebtedness. The 9.125% Notes are jointly and severally guaranteed by substantially all of our direct and indirectsubsidiaries other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States. Interest on the9.125% Notes is payable on April 1 and October 1 of each year. Debt issuance costs related to the 9.125% Notes of approximately $11.6million ($7.7 million, net of amortization) are being amortized over the term of the notes using the effective interest rate method.

On January 7, 2014, we commenced a tender and consent solicitation with respect to the 9.125% Notes. The tender offer price was$1,061.98, inclusive of a $30.00 consent payment, for each $1,000 principal amount of 9.125% Notes, plus accrued and unpaid interest. OnJanuary 22, 2014, we paid $453.7 million for the tendered 9.125% Notes, comprised of $416.2 million of aggregate principal amount of the9.125% Notes, $25.8 million of tender and consent premiums and $11.7 million of accrued interest. After payment for the tendered 9.125%Notes, $8.8 million aggregate principal amount of our 9.125% Notes remains outstanding.

At any time after to April 1, 2014, we may redeem all or a part of the 9.125% Notes upon appropriate notice, at a redemption price of104.563 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning April 1, 2016. If weexperience certain changes in control, we must offer to repurchase the 9.125% Notes at 101.0 percent of the aggregate principal amount,plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

On January 24, 2014, the Indenture was amended to remove most of the restrictions on our ability and the ability of certainsubsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock orsubordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness; (v) create or incur liens; (vi) enter intosale and leaseback transactions; (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate withother entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. The Indenture also was amended toremove certain restrictive covenants designating certain events as Events of Default. Additionally, the remaining restrictive covenants aresubject to a number of important exceptions and qualifications.

Goldman Term LoanIn connection with the ITS Acquisition described in Note 2, Acquisition of ITS, on April 18, 2013, we entered into the $125

million Goldman Term Loan. The Goldman Term Loan was repaid on July 30, 2013 with net proceeds from issuance of the 7.50% Notes.In connection with the repayment of the Goldman Term Loan we incurred debt extinguishment costs of $5.2 million.

2.125% Convertible Senior Notes, due July 2012On July 5, 2007, we issued $125.0 million aggregate principal amount of 2.125% Convertible Notes. As noted above, on May 9,

2012, we repurchased $122.9 million aggregate principal amount of the 2.125% Convertible Notes pursuant to a tender offer. The tenderoffer price was $1,003.27 for each $1,000 principal amount of 2.125% Convertible Notes, plus accrued and unpaid interest. This repurchaseresulted in the recording of debt extinguishment costs of $1.8 million related to the accelerated amortization of both the unamortized debtissuance costs and debt discount associated with the 2.125% Convertible Notes. The remaining $2.1 million aggregate principal amount ofnon-tendered 2.125% Convertible Notes was subsequently paid off at their stated maturity on July 15, 2012.

Amended and Restated Credit AgreementOn December 14, 2012, we entered into an Amended and Restated Credit Agreement (Secured Credit Agreement) consisting of a

senior secured $80.0 million Revolver and senior secured term loan facility (Term Loan) of $50.0 million. The Secured Credit Agreementamended and restated the Prior Credit Agreement. We entered into the Secured Credit Agreement to extend its maturity from May 14, 2013to December 14, 2017 and to decrease the range of Applicable Rates under our

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Revolver. The Secured Credit Agreement provides that, subject to certain conditions, including the approval of the Administrative Agentand the lenders’ acceptance (or additional lenders being joined as new lenders), the amount of the Term Loan or Revolver can be increasedby an additional $50.0 million, so long as after giving effect to such increase, the Aggregate Commitments shall not be in excess of $180.0million.

Our obligations under the Secured Credit Agreement are guaranteed by substantially all of our domestic subsidiaries, each of whichhas executed guaranty agreements; and are secured by first priority liens on our accounts receivable, specified barge rigs and rentalequipment. The Secured Credit Agreement contains customary affirmative and negative covenants with which we were in compliance as ofDecember 31, 2013 and December 31, 2012. The Secured Credit Agreement terminates on December 14, 2017.

On July 19, 2013, we entered into an amendment to our Secured Credit Agreement which, among other things, permits us or any ofour subsidiaries (other than certain immaterial subsidiaries) to incur indebtedness pursuant to additional unsecured senior notes in anaggregate principal amount not to exceed $250.0 million at any one time outstanding; provided that any such notes shall (x) have ascheduled maturity occurring after the maturity date of our Secured Credit Agreement, (y) contain terms (including covenants and events ofdefault) no more restrictive, taken as a whole, to us and our subsidiaries than those contained in our Secured Credit Agreement and (z) haveno scheduled amortization, no sinking fund requirements and no maintenance financial covenants. In addition, pursuant to the amendment,and subject to the terms and conditions set forth in the Secured Credit Agreement, to the extent we repay the principal amount of TermLoans outstanding under our Secured Credit Agreement, until April 30, 2014 we may re-borrow, in the form of additional term loans, up to$45.0 million of the principal amount of such outstanding term loans we have repaid, provided that such $45.0 million borrowing amountwill decrease by $2.5 million at the end of each quarter beginning September 30, 2013 and ending March 31, 2014, such that the borrowingavailability on December 31, 2013 was $40.0 million and on April 30, 2014 would be $37.5 million.

RevolverOur Revolver is available for general corporate purposes and to support letters of credit. Interest on Revolver loans accrues at a Base

Rate plus an Applicable Rate or LIBOR plus an Applicable Rate. Under the Secured Credit Agreement, the Applicable Rate varies from arate per annum ranging from 2.50 percent to 3.00 percent for LIBOR rate loans and 1.50 percent to 2.00 percent for base rate loans,determined by reference to the consolidated leverage ratio (as defined in the Secured Credit Agreement). Under the Prior CreditAgreement, the Applicable Rate varied from a rate per annum ranging from 2.75 percent to 3.25 percent for LIBOR rate loans and 1.75percent to 2.25 percent for base rate loans. Revolving loans are available subject to a borrowing base calculation based on a percentage ofeligible accounts receivable, certain specified barge drilling rigs and rental equipment of the Company and its subsidiary guarantors. Therewere no revolving loans outstanding at December 31, 2013 and December 31, 2012. Letters of credit outstanding as of December 31, 2013and December 31, 2012 totaled $4.6 million and $4.5 million, respectively.

Term LoanThe Term Loan originated at $50.0 million on December 14, 2012 and requires quarterly principal payments of $2.5 million

beginning March 31, 2013. Interest on the Term Loan accrues at a Base Rate plus 2.00 percent or LIBOR plus 3.00 percent. The PriorCredit Agreement required quarterly principal payments of $6.0 million, and interest accrued at a Base Rate plus 2.25 percent or LIBORplus 3.25 percent. The were no borrowings on the Term Loan at December 31, 2013. The outstanding balance under the Term Loan as ofDecember 31, 2012 was $50.0 million.

Note 9 — Derivative Financial InstrumentsDuring the 2011 second quarter, we entered into two variable-to-fixed interest rate swap agreements as a strategy to manage the

floating rate risk on the Term Loan borrowings under the Secured Credit Agreement. The two agreements fixed the interest rate on anotional amount of $73.0 million of borrowings at 3.878 percent for the period beginning June 27, 2011 and terminating May 14, 2013.The notional amount of the swap agreements decreased correspondingly with amortization of the Term Loan under the Prior CreditAgreement. We did not apply hedge accounting to the agreements and, accordingly, change in the fair value of the interest rate swaps wererecognized in earnings. As of December 31, 2013 the swap agreements had expired and as of December 31, 2012, the fair value of theinterest rate swap was a liability of $0.1 million and was recorded in accrued liabilities in our consolidated balance sheets. For the yearended December 31, 2013, we recognized in earnings a nominal gain relating to these contracts. For both years ended December 31, 2012and December 31, 2011 we recognized a nominal loss, relating to these contracts.

Note 10 — Fair Value of Financial InstrumentsCertain of our assets and liabilities are required to be measured at fair value on a recurring basis. For purposes of recording fair value

adjustments for certain financial and non-financial assets and liabilities, and determining fair value

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disclosures, we estimate fair value at a price that would be received to sell an asset or paid to transfer a liability in an orderly transactionbetween market participants in the principal market for the asset or liability.

The FASB fair value measurement and disclosure guidance requires inputs that we categorize using a three-level hierarchy, fromhighest to lowest level of observable inputs, as follows:

Level 1 — Unadjusted quoted prices for identical assets or liabilities in active marketsLevel 2 — Direct or indirect observable inputs, including quoted prices or other market data, for similar assets or liabilities inactivemarkets or identical assets or liabilities in less active markets andLevel 3 — Unobservable inputs that require significant judgment for which there is little or no market data.When multiple input levels are required for a valuation, we categorize the entire fair value measurement according to the lowest level

of input that is significant to the measurement even though we may have also utilized significant inputs that are more readily observable.The amounts reported in our consolidated balance sheets for cash and cash equivalents, accounts receivable, and accounts payableapproximate fair value. The carrying amount of our interest rate swap agreements represents the estimated fair value, measured using Level2 inputs. As of December 31, 2013 the swap agreements had expired and as of December 31, 2012, the fair value of the interest rate swapwas a liability of $0.1 million and was recorded in accrued liabilities in our consolidated balance sheets.

Fair value of our debt instruments is determined using Level 2 inputs. Fair values and related carrying values of our debt instrumentsare as follows:

December 31, 2013 December 31, 2012

Carrying Amount Fair Value Carrying Amount Fair Value (in thousands)Long-term Debt

7.50% Notes $ 225,000 $ 236,250 $ — $ —9.125% Notes 425,000 446,250 425,000 453,688

Total $ 650,000 $ 682,500 $ 425,000 $ 453,688

As discussed in Note 4, in accordance with the impairment or disposal of long-lived assets guidance, during the fourth quarter of2011, our arctic-class rigs with a carrying value as of December 31, 2011 of $339.5 million were written down to their estimated fair valueof $169.5 million, resulting in a pretax non-cash charge of $170.0 million which is included in earnings for the period. The fair value wasbased on expected future cash flows using Level 3 inputs.

The assets acquired and liabilities assumed in the ITS Acquisition were recorded at fair value in accordance with U.S. GAAP.Acquisition date fair values represent either Level 2 fair value measurements (current assets and liabilities, property, plant and equipment)or Level 3 fair value measurements (intangible assets).

Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or Level 2 to Level 3. There were no transfersbetween levels of the fair value hierarchy or any changes in the valuation techniques used during the year ended December 31, 2013.

Note 11 — Common Stock and Stockholders’ EquityStock Plans — The Company’s employee and non-employee director stock plans are summarized as follows:The 2010 Long-Term Incentive Plan, as amended and restated (the Plan) was approved by the stockholders at the Annual Meeting of

Stockholders on May 8, 2013. The Plan authorizes the compensation committee or the board of directors to issue stock options, stockappreciation rights, RSAs, RSUs, PAUs and other types of awards in cash or stock to key employees, consultants, and directors. Themaximum number of shares that may be delivered pursuant to the awards granted under the Amended and Restated 2010 Long TermIncentive Plan is 11,000,000 shares of common stock. As of December 31, 2013 there were 5,130,182 shares remaining available under thePlan.

For service-based awards and performance-based awards with graded vesting conditions, we recognize compensation expense on astraight-line basis over the service period for each separately vesting portion of the award as if the award was, in substance, multipleawards. For market-based awards that vest at the end of the service period, we recognize compensation expense on a straight-line basisthrough the end of the service period. Share-based awards generally vest over three years. Share-based compensation expense isrecognized, net of an estimated forfeiture rate, which is based on historical experience and adjusted, if necessary, in subsequent periodsbased on actual forfeitures. The fair value of nonvested RSAs and RSUs is determined based on the closing trading price of the company’sshares on the grant date. Our RSAs and RSUs are settled in stock upon vesting. Our PAU awards can be settled in cash or stock, or acombination of cash and stock. We evaluate the terms

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of each PAU award to determine if the award should be accounted for as equity or a liability under the stock compensation rules of U.S.GAAP.

We recognize share-based compensation expense in the same financial statement line item as cash compensation paid to therespective employees. Tax deduction benefits for awards in excess of recognized compensation costs are reported as a financing cash flow.

On September 17, 2012, Gary Rich was elected as President, Chief Executive Officer and Director of the Company. As part of hisemployment agreement, he was granted 349,651 RSUs. Additionally, on May 9, 2013 Chris Weber was elected Senior Vice President andChief Financial Officer of the Company. As part of his employment agreement, he was granted 261,438 RSUs. Both of these awards weregranted outside of the Company’s 2010 Plan but are subject to substantially the same terms and conditions of other service-based RSUsgranted by the Company to its executive officers.

Information regarding the Company’s Long-Term Incentive plans is summarized below:

Nonvested Shares Shares

WeightedAverage

Grant-DateFair

ValueNonvested at January 1, 2013 2,812,482 $ 5.15Granted 2,602,973 4.77Vested (1,636,373) 5.00Forfeited (370,727) 5.02Nonvested at December 31, 2013 3,408,355 $ 4.97

In 2013 and 2012, we issued 2,602,973 and 1,558,347, respectively, of restricted shares to selected key personnel. Total stock-basedcompensation expense recognized for the years ended December 31, 2013, 2012, and 2011 was $9.4 million, $7.2 million, and $5.9million, respectively, all of which was related to nonvested stock. The total fair value of the shares vested during the years endedDecember 31, 2013, 2012, and 2011 was $7.4 million, $5.2 million, and $6.9 million, respectively. The fair value of RSAs and RSUs isdetermined based on the closing trading price of the company’s shares on the grant date. The weighted-average grant-date fair value ofshares granted during the years 2013, 2012, and 2011 was $4.77, $5.37, and $5.61, respectively. Stock-based compensation expense isincluded in our consolidated statements of operations in both “General and administration expense” and “Operating expenses.”

Nonvested RSUs at December 31, 2013 totaled 3,408,355 shares and total unrecognized compensation cost related to unamortizednonvested stock awards was $8.4 million as of December 31, 2013. The remaining unrecognized compensation cost related to non-vestedstock awards will be amortized over a weighted-average vesting period of approximately 20.8 months.

During the years ended December 31, 2013 and 2012, we granted to certain of our officers and key employees a total of 18,000 and38,429 PAUs under the Plan, respectively. Subsequent to the award of these PAUs, 13,358 and 3,955 units were forfeited during 2013 and2012, respectively. Incentive grants included in this issuance were based on the attainment of pre-established performance goals. Each PAUhas a nominal value of $100.00. Awards are dependent upon our total stockholder return and return on capital employed relative to a peergroup of companies over a three-year performance period. A maximum of 200 percent of the number of PAUs granted may be earned ifperformance at the maximum level is achieved. Compensation expense recognized related to the PAUs for the years ended December 31,2013, 2012, and 2011 was $1.8 million, $0.5 million, and $2.1 million, respectively.

As of December 31, 2013 and 2012, we had no stock options outstanding or exercisable and we had 668,897 and 1,709,963 sharesheld in treasury stock, respectively.

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Note 12 — Reconciliation of Income and Number of Shares Used to Calculate Basic and Diluted Earnings per Share (EPS)

For the Year Ended December 31, 2013

Income

(Numerator) Shares

(Denominator) Per-ShareAmount

Basic EPS $ 27,015,000 119,284,468 $ 0.23 Effect of dilutive securities: Stock options and restricted stock 1,940,082 $ (0.01) Diluted EPS $ 27,015,000 121,224,550 $ 0.22 For the Year Ended December 31, 2012

Income

(Numerator) Shares

(Denominator) Per-ShareAmount

Basic EPS $ 37,313,000 117,721,135 $ 0.32 Effect of dilutive securities: Stock options and restricted stock 1,372,455 $ (0.01) Diluted EPS: $ 37,313,000 119,093,590 $ 0.31 For the Year Ended December 31, 2011

Income

(Numerator) Shares

(Denominator) Per-ShareAmount

Basic EPS $ (50,451,000) 116,081,590 $ (0.43) Effect of dilutive securities: Stock options and restricted stock — $ — Diluted EPS: $ (50,451,000) 116,081,590 $ (0.43)

For the years ended December 31, 2013 and 2012, weighted-average shares outstanding used in our computation of diluted EPSincludes the dilutive effect of potential common shares. For the year ended December 31, 2011, all potential common shares have beenexcluded from the calculation of weighted-average shares outstanding used in our computation of diluted EPS as the company incurred aloss for that year, and therefore, inclusion of potential common shares in the calculation of diluted EPS would be anti-dilutive.

Note 13 — Employee Benefit PlanThe Company sponsors a defined contribution 401(k) plan (Plan) in which substantially all U.S. employees are eligible to participate.

The Company matches 100 percent of each participant’s pre-tax contributions in an amount not exceeding 4 percent of the participant'scompensation and 50 percent of each participant’s pre-tax contributions in an amount not exceeding 2 percent of the participant'scompensation, up to the maximum amounts of contributions allowed by law. The costs of our matching contributions to the Plan were $3.6million, $2.8 million and $2.4 million in 2013, 2012 and 2011, respectively. Employees become 100 percent vested in the employer matchcontributions immediately upon participation in the Plan. Coverage for office based employees begins on the date of hire. For rig-based andrental tools employees, coverage begins on the first of the month following completion of 30 calendar days of continuous full-timeemployment.

Note 14 — Reportable SegmentsOur business is comprised of five segments: (1) Rental Tools, (2) U.S. Barge Drilling, (3) U.S. Drilling, (4) International Drilling, and

(5) Technical Services. Historically, we reported a sixth segment, Construction Contract, for which there was no activity during the ninemonths ended September 30, 2013 or the year ended December 31, 2012. As a result of activity in the fourth quarter of 2013, this segmenthas been included in this report. We eliminate inter-segment revenue and expenses. The following table represents the results of operationsby reportable segment:

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Year Ended December 31,

Operations by Reportable Industry Segment: 2013 2012 2011 (Dollars in Thousands)Revenues:

Rental Tools(1) $ 310,041 $ 246,900 $ 237,068U.S. Barge Drilling(1) 136,855 123,672 93,763U.S. Drilling(1) 66,928 1,387 —International Drilling(1) 333,962 291,772 318,481Technical Services(1) 26,386 14,030 27,284Construction Contract(1) — — 9,638

Total revenues 874,172 677,761 686,234Operating income:

Rental Tools(2) 91,164 113,899 120,822U.S. Barge Drilling(2) 51,257 39,608 11,115U.S. Drilling(2) (4,484) (15,168) (3,915)International Drilling(2) 23,732 13,138 22,948Technical Services(2) 2,050 79 5,680Construction Contract(2) 4,728 — 771

Total operating gross margin 168,447 151,556 157,421General and administrative expense (68,025) (46,257) (31,567)Impairments and other charges — — (170,000)Provision for reduction in carrying value of certain assets (2,544) — (1,350)Gain on disposition of assets, net 3,994 1,974 3,659Total operating income (loss) 101,872 107,273 (41,837)Interest expense (47,820) (33,542) (22,594)Interest income 2,450 153 256Loss on extinguishment of debt (5,218) (2,130) —Changes in fair value of derivative positions 53 55 (110)Other 1,450 (832) (1,127)Income (loss) from continuing operations before income taxes $ 52,787 $ 70,977 $ (65,412) 2013 2012 Identifiable assets:

Rental Tools $ 350,429 $ 194,600

U.S. Barge Drilling 89,884 99,409 U.S. Drilling 354,208 369,683 International Drilling 460,461 414,546

Total identifiable assets 1,254,982 1,078,238 Corporate and other assets(3) 279,774 177,495

Total assets $ 1,534,756 $ 1,255,733 1) In 2013, our largest customer, Exxon Neftegas Limited (ENL), constituted approximately 15.6 percent, respectively, of our total

consolidated revenues and approximately 38.3 percent of our International Drilling segment and 33.9 percent of our Technical Servicessegment. In 2012, our two largest customers, ENL and Schlumberger, constituted approximately 12 percent and 10 percent,respectively, of our total consolidated revenues and approximately 27 percent and 24 percent of our International Drilling segment,respectively. In 2011, our largest customer, ENL constituted approximately 16 percent of our total revenues and approximately 34percent of our International Drilling segment.

2) Operating income is calculated as revenues less direct operating expenses, including depreciation and amortizationexpense.

3) This category includes corporate assets as well as minimal assets for our Technical Services segment primarily related to officefurniture and fixtures.

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Year Ended December 31,

Operations by Reportable Industry Segment: 2013 2012 2011 (Dollars in Thousands)Capital expenditures:

Rental Tools $ 76,928 $ 61,958 $ 61,702U.S. Barge Drilling 23,694 8,808 7,339U.S. Drilling 1,809 86,786 99,915International Drilling 39,115 15,240 15,011Corporate 14,099 18,751 6,432

Total capital expenditures $ 155,645 $ 191,543 $ 190,399Depreciation and amortization:

Rental Tools 54,625 42,944 40,497U.S. Barge Drilling 13,796 13,906 17,006U.S. Drilling 16,120 7,011 2,223International Drilling 46,022 45,967 48,965Corporate and other (1) 3,490 3,189 3,445

Total depreciation and amortization $ 134,053 $ 113,017 $ 112,1361) This category includes depreciation of corporate assets as well as minimal depreciation for our Technical Services segment primarily

related to office furniture and fixtures.

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Year Ended December 31,

Operations by Geographic Area: 2013 2012 2011 (Dollars in Thousands)Revenues:

Africa and Middle East $ 58,416 $ 26,528 $ 6,774Asia Pacific 170,165 117,392 147,643CIS 55,165 44,312 67,255Europe 16,788 — —Latin America 120,261 103,540 96,810United States 453,377 385,989 367,752

Total revenues 874,172 677,761 686,234Operating gross margin:

Africa and Middle East(1) (383) (2,027) (8,724)Asia Pacific(1) 21,995 16,550 23,528CIS(1) 11,888 (9,580) 8,709Europe(1) 274 — —Latin America(1) 1,140 9,581 1,126United States(1) 133,533 137,032 132,782

Total operating gross margin 168,447 151,556 157,421General and administrative expense (68,025) (46,257) (31,567)Impairments and other charges — — (170,000)Provision for reduction in carrying value of certain assets (2,544) — (1,350)Gain on disposition of assets, net 3,994 1,974 3,659Total operating income (loss) 101,872 107,273 (41,837)Interest expense (47,820) (33,542) (22,594)Interest income 2,450 153 256Loss on extinguishment of debt (5,218) (2,130) —Changes in fair value of derivative positions 53 55 (110)Other 1,450 (832) (1,127)Income (loss) from continuing operations before income taxes $ 52,787 $ 70,977 $ (65,412)Long-lived assets:(2)

Africa and Middle East $ 110,336 $ 25,032 Asia Pacific 44,606 18,688 CIS 55,722 110,848 Europe 82,473 — Latin America 15,198 63,899

United States 563,021 574,730 Total long-lived assets $ 871,356 $ 793,197 1) Operating income is calculated as revenues less direct operating expenses, including depreciation and amortization

expense.2) Long-lived assets primarily consist of property, plant and equipment, net and exclude assets held for sale, if

any.

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Note 15 — Commitments and ContingenciesThe Company has various lease agreements for office space, equipment, vehicles and personal property. These obligations extend

through 2025 and are typically non-cancelable. Most leases contain renewal options and certain of the leases contain escalation clauses.Future minimum lease payments at December 31, 2013, under operating leases with non-cancelable terms are as follows:

Year Ended December 31,

(Dollars in Thousands)2014 13,9792015 9,4882016 7,5922017 7,1142018 5,944

Thereafter 7,988Total $ 52,105

Total rent expense for all operating leases amounted to $19.9 million for 2013, $11.8 million for 2012 and $12.1 million for 2011.We are self-insured for certain losses relating to workers’ compensation, employers’ liability, general liability (for onshore liability),

protection and indemnity (for offshore liability) and property damage. Our exposure (that is, the retention or deductible) per occurrence is$250,000 for worker’s compensation, employer’s liability, $500,000 general liability, protection and indemnity and maritime employers’liability (Jones Act). In addition, we assume a $500,000 annual aggregate deductible for protection and indemnity and maritime employers’liability claims. The annual aggregate deductible is reduced by every dollar that exceeds the $500,000 per occurrence retention. We alsoassume a retention for foreign casualty exposures of $100,000 for workers’ compensation, employers’ liability, and $1,000,000 for generalliability losses and a $100,000 deductible for auto liability claims. For all primary insurances mentioned above, the Company has excesscoverage for those claims that exceed the retention and annual aggregate deductible. We maintain actuarially-determined accruals in ourconsolidated balance sheets to cover the self-insurance retentions.

We have self-insured retentions for certain other losses relating to rig, equipment, property, business interruption and political, war,and terrorism risks which vary according to the type of rig and line of coverage. Political risk insurance is procured for internationaloperations. However, this coverage may not adequately protect us against liability from all potential consequences.

As of December 31, 2013 and 2012, our gross self-insurance accruals for workers’ compensation, employers’ liability, generalliability, protection and indemnity and maritime employers’ liability totaled $5.7 million and $4.7 million, respectively and the relatedinsurance recoveries/receivables were $1.7 million and $1.2 million, respectively.

We have entered into employment agreements with terms of one to two years with certain members of management with automaticone year renewal periods at expiration dates. The agreements provide for, among other things, compensation, benefits and severancepayments. The employment agreements also provide for lump sum compensation and benefits in the event of termination within two yearsfollowing a change in control of the Company.

We are a party to various lawsuits and claims arising out of the ordinary course of business. We estimate the range of our liabilityrelated to pending litigation when we believe the amount or range of loss can be estimated. We record our best estimate of a loss when theloss is considered probable. When a liability is probable and there is a range of estimated loss with no best estimate in the range, we recordthe minimum estimated liability related to the lawsuits or claims. As additional information becomes available, we assess the potentialliability related to our pending litigation and claims and revise our estimates. Due to uncertainties related to the resolution of lawsuits andclaims, the ultimate outcome may differ significantly from our estimates. In the opinion of management and based on liability accrualsprovided, our ultimate exposure with respect to these pending lawsuits and claims is not expected to have a material adverse effect on ourconsolidated financial position or cash flows, although they could have a material adverse effect on our results of operations for a particularreporting period.

Asbestos-Related ClaimsWe are from time to time a party to various lawsuits that are incidental to our operations in which the claimants seek an unspecified

amount of monetary damages for personal injury, including injuries purportedly resulting from exposure to asbestos on drilling rigs andassociated facilities. At December 31, 2013, there were approximately 15 of these lawsuits in which we are one of many defendants. Theselawsuits have been filed in the United States in the State of Mississippi.

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Our subsidiaries named in these asbestos-related lawsuits intend to defend themselves vigorously and, based on the informationavailable to us at this time, we do not expect the outcome to have a material adverse effect on our financial condition, results of operationsor cash flows. However, we are unable to predict the ultimate outcome of these lawsuits. No amounts were accrued at December 31, 2013.

Customs Agent and Foreign Corrupt Practices Act (FCPA) SettlementOn April 16, 2013, the Company and the Department of Justice (DOJ) entered into a deferred prosecution agreement (DPA), under

which the DOJ will defer for three years prosecuting the Company for criminal violations of the anti-bribery provisions of the FCPArelating to the Company’s retention and use of an individual agent in Nigeria with respect to certain customs-related issues, in return for: (i)the Company’s acceptance of responsibility for, and agreement not to contest or contradict the truthfulness of, the statement of facts andallegations that have been filed in a United States District Court concurrently with the DPA; (ii) the Company’s payment of anapproximately $11.76 million fine; (iii) the Company’s reaffirming its commitment to compliance with the FCPA and other applicable anti-corruption laws in connection with the Company’s operations, and continuing cooperation with domestic and foreign authorities inconnection with the matters that are the subject of the DPA; (iv) the Company’s commitment to continue to address any identified areas forimprovement in the Company’s internal controls, policies and procedures relating to compliance with the FCPA and other applicable anti-corruption laws if, and to the extent, not already addressed; and (v) the Company’s agreement to report to the DOJ in writing annuallyduring the term of the DPA regarding remediation of the matters that are the subject of the DPA, implementation of any enhanced internalcontrols, and any evidence of improper payments the Company may have discovered during the term of the agreement. If the Companyremains in compliance with the terms of the DPA throughout its effective period, the charge against the Company will be dismissed withprejudice. The Company also settled a related civil complaint filed by the SEC in a United States District Court.

Demand Letter and Derivative LitigationIn April 2010, we received a demand letter from a law firm representing Ernest Maresca. The letter states that Mr. Maresca is one

of our stockholders and that he believes that certain of our current and former officers and directors violated their fiduciary duties related tothe issues described above under “Customs Agent and Foreign Corrupt Practices Act (FCPA) Settlement.” The letter requests that ourBoard of Directors take action against the individuals in question. In response to this letter, the Board formed a special committee toevaluate the issues raised by the letter and determine a course of action for the Company. The special committee engaged its own counselfor the investigation and evaluated potential claims against all individuals identified in the demand letter. The special committee consideredwhether pursuing each of the individuals named in the demand letter was in the best interests of the Company based upon a variety offactors, including among others, whether the Company had a potential cause of action against the individual, the defenses the individualmight offer to such a claim, theability of the individual to satisfy any judgment the Company might secure as a result of a claim asserted, and other risks to theCompany of pursuing the claims. After taking various factors into account, on July 29, 2013, the special committee recommended to theBoard that the Company not pursue any action against the current and former officers and directors namedin the demand letter, and the Board accepted such recommendation.

ITS Internal ControlsOur due diligence process with respect to the ITS Acquisition identified certain transactions that suggest that ITS' internal controls

may have failed to prevent violations of potentially applicable international trade and anti-corruption laws, including those of the UnitedKingdom. We have investigated such violations and have and will, as appropriate, make any identified violations known to relevantauthorities, cooperate with any resulting investigations and take proper remediation measures (including seeking any necessary governmentauthorizations). While it is possible that matters may arise where a contingency may require further accounting considerations, we do notbelieve that as a result of these matters a loss is probable and estimable at this time.

Note 16 — Related Party TransactionsConsulting Agreement

The Company was a party to a consulting agreement with Robert L. Parker Sr., the former Chairman of the Board of Directors of theCompany and the father of our current Executive Chairman, Robert L. Parker Jr. The consulting agreement expired on April 30, 2011.Under the agreement, Mr. Parker Sr. was paid consulting fees of $40,000 during the year ended December 31, 2011. For one year after thetermination of the consulting agreement, Mr. Parker Sr. was prohibited from soliciting business from any of our customers or individualswith which we have done business, from becoming interested in any business that competes with the Company, and from recruiting anyemployees of the Company. Under the consulting agreement, Mr. Parker Sr. also represented the Company on the U.S.-KazakhstanBusiness Council. In addition, we pay a

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monthly rental fee to Mr. Parker Sr. for various pieces of artwork which are displayed throughout our corporate office. We paid Mr. Parker$36,000 for each of the years ended December 31, 2013, 2012, and 2011 for the artwork rental.

Effective January 1, 2012, the Company entered into two separate ranch lease agreements under which the Company agreed to pay adaily usage fee per person for utilization of the Cypress Springs Ranch owned by the Robert L. Parker, Sr. and Catherine M. Parker FamilyLimited Partnership and the Camp Verde Ranch owned by Robert L. Parker, Jr. During 2013, the Company incurred fees of $14,281 in2013 for the Cypress Springs Ranch. During 2012, the company incurred fees of $39,875 and $1,650 in 2012 for the Cypress SpringsRanch and Camp Verde Ranch, respectively, pursuant to the ranch lease agreements for the right to utilize the premises of the ranches forthe purpose of hosting business meetings.

Other Related Party AgreementsDuring 2013 and 2012, one of the Company’s directors held executive positions at Apache Corporation (Apache), including the

positions of President and Chief Corporate Officer, Executive Vice President and Chief Financial Officer and Chief Corporate Officer.During 2013 and 2012, affiliates of Apache paid affiliates of the Company a total of $40.8 million and $31.2 million, respectively, forperformance of drilling services and provision of rental tools. Also during 2013, one of our directors served on the board of directors ofGardner Denver, Inc. (GD). During 2013, affiliates of the Company paid affiliates of GD $0.2 million for goods and services provided tothe Company. This information is considered and discussed annually in connection with the Board of Directors’ assessment of facts andcircumstances that could preclude a determination that such director is independent under the New York Stock Exchange governancelisting standards.

Note 17 — Supplementary InformationAt December 31, 2013, accrued liabilities included $8.1 million of deferred mobilization fees, $16.8 million of accrued interest

expense, $2.7 million of worker’s compensation liabilities and $33.5 million of accrued payroll and payroll taxes. Other long-termobligations included $3.0 million of workers’ compensation liabilities as of December 31, 2013.

At December 31, 2012, accrued liabilities included $1.6 million of deferred mobilization fees, $9.7 million of accrued interestexpense, $2.3 million of worker’s compensation liabilities and $26.0 million of accrued payroll and payroll taxes. Other long-termobligations included $2.5 million of workers’ compensation liabilities as of December 31, 2012.

Note 18 — Parent, Guarantor, Non-Guarantor Unaudited Consolidating Condensed Financial StatementsSet forth on the following pages are the consolidating condensed financial statements of Parker Drilling. The Company’s Secured

Credit Agreement and Senior Notes are fully and unconditionally guaranteed by substantially all of our direct and indirect domesticsubsidiaries other than immaterial subsidiaries and subsidiaries generating revenues primarily outside the United States, subject to thefollowing customary release provisions:

• in connection with any sale or other disposition of all or substantially all of the assets of that guarantor (including by way ofmerger or consolidation) to a person that is not (either before or after giving effect to such transaction) a subsidiary of theCompany;

• in connection with any sale of such amount of capital stock as would result in such guarantor no longer being a subsidiary to aperson that is not (either before or after giving effect to such transaction) a subsidiary of the Company;

• if the Company designates any restricted subsidiary that is a guarantor as an unrestrictedsubsidiary;

• if the guarantee by a guarantor of all other indebtedness of the Company or any other guarantor is released, terminated ordischarged, except by, or as a result of, payment under such guarantee; or

• upon legal defeasance or covenant defeasance (satisfaction and discharge of theindenture).

There are currently no restrictions on the ability of the restricted subsidiaries to transfer funds to Parker Drilling in the form of cashdividends, loans or advances. Parker Drilling is a holding company with no operations, other than through its subsidiaries. Separatefinancial statements for each guarantor company are not provided as the company complies with the exception to Rule 3-10(a)(1) ofRegulation S-X, set forth in sub-paragraph (f) of such rule. All guarantor subsidiaries are owned 100 percent by the parent company.

We are providing consolidating condensed financial information of the parent, Parker Drilling, the guarantor subsidiaries, and thenon-guarantor subsidiaries as of December 31, 2013 and December 31, 2012 and for the years ended December 31, 2013, 2012, and 2011.The consolidating condensed financial statements present investments in both consolidated and unconsolidated subsidiaries using theequity method of accounting.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)(Unaudited)

Year ended December 31, 2013

Parent Guarantor Non-Guarantor Eliminations ConsolidatedTotal revenues $ — $ 468,073 $ 549,295 $ (143,196) $ 874,172Operating expenses — 252,211 462,657 (143,196) 571,672Depreciation and amortization — 77,416 56,637 — 134,053Total operating gross margin — 138,446 30,001 — 168,447General and administration expense (1) (202) (67,083) (740) — (68,025)Provision for reduction in carrying valueof certain assets — — (2,544) — (2,544)Gain on disposition of assets, net — 1,759 2,235 — 3,994Total operating income (loss) (202) 73,122 28,952 — 101,872Other income and (expense):

Interest expense (51,439) (335) (9,930) 13,884 (47,820)Changes in fair value of derivativepositions 53 — — — 53Interest income 3,824 1,761 10,749 (13,884) 2,450Loss on extinguishment of debt (5,218) — — — (5,218)Other (1) (143) 1,594 — 1,450Equity in net earnings of subsidiaries 55,430 — — (55,430) —

Total other income (expense) 2,649 1,283 2,413 (55,430) (49,085)Income (loss) before income taxes 2,447 74,405 31,365 (55,430) 52,787Income tax expense (benefit):

Current (21,431) 18,737 15,603 — 12,909Deferred (3,137) 19,454 (3,618) — 12,699

Income tax expense (benefit) (24,568) 38,191 11,985 — 25,608Net income (loss) 27,015 36,214 19,380 (55,430) 27,179Less: Net (loss) attributable tononcontrolling interest — — 164 — 164Net income (loss) attributable tocontrolling interest $ 27,015 $ 36,214 $ 19,216 $ (55,430) $ 27,015(1) General and administration expenses for field operations are included in operating

expenses.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)(Unaudited)

Year ended December 31, 2012

Parent Guarantor Non-Guarantor Eliminations ConsolidatedTotal revenues $ — $ 393,738 $ 385,279 $ (101,256) $ 677,761Operating expenses — 184,946 329,498 (101,256) 413,188Depreciation and amortization — 65,354 47,663 — 113,017Total operating gross margin — 143,438 8,118 — 151,556General and administration expense (1) (182) (45,758) (317) — (46,257)Gain on disposition of assets, net — 775 1,199 — 1,974Total operating income (loss) (182) 98,455 9,000 — 107,273Other income and (expense):

Interest expense (37,326) (151) (8,739) 12,674 (33,542)Interest income 9,863 5,073 41,999 (56,782) 153Loss on extinguishment of debt (2,130) — — — (2,130)Changes in fair value of derivativepositions 55 — — — 55Other — (206) (626) — (832)Equity in net earnings of subsidiaries 43,884 — — (43,884) —

Total other income (expense) 14,346 4,716 32,634 (87,992) (36,296)Income (loss) before income taxes 14,164 103,171 41,634 (87,992) 70,977Income tax expense (benefit):

Current (25,406) 32,781 10,667 — 18,042Deferred 2,257 15,429 (1,849) — 15,837

Income tax expense (benefit) (23,149) 48,210 8,818 — 33,879Net income (loss) 37,313 54,961 32,816 (87,992) 37,098Less: Net (loss) attributable tononcontrolling interest — — (215) — (215)Net income (loss) attributable tocontrolling interest 37,313 54,961 33,031 (87,992) 37,313______________________(1) General and administration expenses for field operations are included in operating

expenses.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATING CONDENSED STATEMENT OF OPERATIONS

(Dollars in Thousands)(Unaudited)

Year ended December 31, 2011

Parent Guarantor Non-Guarantor Eliminations ConsolidatedTotal revenues $ — $ 375,798 $ 426,491 $ (116,055) $ 686,234Operating expenses — 174,955 357,777 (116,055) 416,677Depreciation and amortization — 62,744 49,392 — 112,136Total operating gross margin — 138,099 19,322 — 157,421General and administration expense (1) (218) (30,968) (381) — (31,567)Impairment and other charges — (170,000) — — (170,000)Provision for reduction in carrying valueof certain assets — (1,350) — — (1,350)Gain on disposition of assets, net — 2,706 953 — 3,659Total operating income (loss) (218) (61,513) 19,894 — (41,837)Other income and (expense):

Interest expense (26,654) (17,889) (8,865) 30,814 (22,594)Interest income 18,131 750 12,189 (30,814) 256Loss on extinguishment of debt — — — — —Changes in fair value of derivativepositions (110) — — — (110)Other — (315) (812) — (1,127)Equity in net earnings of subsidiaries (23,484) — — 23,484 —

Total other income and (expense) (32,117) (17,454) 2,512 23,484 (23,575)Income (loss) before income taxes (32,335) (78,967) 22,406 23,484 (65,412)Income tax expense (benefit):

Current (13,402) 27,169 19,841 — 33,608Deferred 31,518 (57,030) (22,863) — (48,375)

Total income tax expense (benefit) 18,116 (29,861) (3,022) — (14,767)Net income (loss) (50,451) (49,106) 25,428 23,484 (50,645)Less: Net (loss) attributable tononcontrolling interest $ — $ — $ (194) $ — $ (194)Net income (loss) attributable tocontrolling interest (50,451) (49,106) 25,622 23,484 (50,451)_______________________(1) General and administration expenses for field operations are included in operating

expenses.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)(Unaudited)

December 31, 2013

Parent Guarantor Non-Guarantor Eliminations ConsolidatedASSETS

Current assets: Cash and cash equivalents $ 88,697 $ 8,310 $ 51,682 $ — $ 148,689Accounts and notes receivable, net — 101,299 156,590 — 257,889Rig materials and supplies — 3,002 38,779 — 41,781Deferred costs — — 13,682 — 13,682Deferred income taxes (57) 8,435 1,562 — 9,940Other tax assets 54,524 (46,770) 16,325 — 24,079Other current assets — 9,089 14,134 — 23,223

Total current assets 143,164 83,365 292,754 — 519,283Property, plant and equipment, net 60 562,148 309,148 — 871,356Investment in subsidiaries andintercompany advances 1,906,128 (336,570) 1,667,937 (3,237,495) —Other noncurrent assets (457,954) 468,864 250,983 (117,776) 144,117

Total assets $ 1,591,398 $ 777,807 $ 2,520,822 $ (3,355,271) $ 1,534,756LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities: Current portion of long-term debt $ 25,000 $ — $ — $ — $ 25,000Accounts payable and accrued liabilities 75,268 92,546 261,436 (254,364) 174,886Accrued income taxes — 725 6,541 — 7,266

Total current liabilities 100,268 93,271 267,977 (254,364) 207,152Long-term debt 628,781 — — — 628,781Other long-term liabilities 5,037 6,743 15,134 — 26,914Long-term deferred tax liability — 51,747 (12,980) — 38,767Intercompany payables 227,504 291,783 422,645 (941,932) —Contingencies — — — — —Stockholders’ equity:

Common stock 20,075 18,049 43,003 (61,052) 20,075Capital in excess of par value 657,349 740,438 1,572,919 (2,313,357) 657,349Accumulated other comprehensiveincome — — 1,888 — 1,888Retained earnings (accumulated deficit) (47,616) (424,224) 208,790 215,434 (47,616)

Total controlling intereststockholders’ equity 629,808 334,263 1,826,600 (2,158,975) 631,696

Noncontrolling interest — — 1,446 — 1,446Total Equity 629,808 334,263 1,828,046 (2,158,975) 633,142

Total liabilities and stockholders’equity $ 1,591,398 $ 777,807 $ 2,520,822 $ (3,355,271) $ 1,534,756

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATING CONDENSED BALANCE SHEET

(Dollars in Thousands)(Unaudited)

December 31, 2012

Parent Guarantor Non-Guarantor Eliminations ConsolidatedASSETS

Current assets: Cash and cash equivalents $ 42,251 $ 11,023 $ 34,612 $ — $ 87,886Accounts and notes receivable, net (7) 77,927 90,695 — 168,615Rig materials and supplies — 2,835 26,587 — 29,422Deferred costs — — 1,089 — 1,089Deferred income taxes — 7,615 1,127 — 8,742Other tax assets 46,249 (31,136) 18,411 — 33,524Other current assets — 8,708 4,145 — 12,853

Total current assets 88,493 76,972 176,666 — 342,131Property, plant and equipment, net 60 548,794 244,343 — 793,197Investment in subsidiaries andintercompany advances 1,492,708 (523,143) 1,467,617 (2,437,182) —Other noncurrent assets (378,297) 370,877 219,196 (91,371) 120,405

Total assets $ 1,202,964 $ 473,500 $ 2,107,822 $ (2,528,553) $ 1,255,733LIABILITIES AND STOCKHOLDERS’ EQUITY

Current liabilities: Current portion of long-term debt $ 10,000 $ — $ — $ — $ 10,000Accounts payable and accrued liabilities 65,839 94,037 205,864 (227,994) 137,746Accrued income taxes — 612 3,508 — 4,120

Total current liabilities 75,839 94,649 209,372 (227,994) 151,866Long-term debt 469,205 — — — 469,205Other long-term liabilities 3,933 6,129 13,120 — 23,182Long-term deferred tax liability — 36,894 (16,047) — 20,847Intercompany payables 62,583 43,657 216,369 (322,609) —Contingencies — — — — —Stockholders’ equity:

Common stock 19,818 18,049 43,003 (61,052) 19,818Capital in excess of par value 646,217 733,112 1,455,246 (2,188,358) 646,217Retained earnings (accumulated deficit) (74,631) (458,990) 187,530 271,460 (74,631)

Total controlling intereststockholders’ equity 591,404 292,171 1,685,779 (1,977,950) 591,404

Noncontrolling interest — — (771) — (771)Total Equity 591,404 292,171 1,685,008 (1,977,950) 590,633

Total liabilities andstockholders’ equity $ 1,202,964 $ 473,500 $ 2,107,822 $ (2,528,553) $ 1,255,733

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)(Unaudited)

Year Ended December 31, 2013

Parent Guarantor Non-Guarantor Eliminations ConsolidatedComprehensive income: Net income $ 27,015 $ 36,214 $ 19,380 $ (55,430) $ 27,179Other comprehensive gain, net of tax:

Currency translation difference on related borrowings — — (1,525) — (1,525)Currency translation difference on foreign currency netinvestments — — 3,051 — 3,051

Total other comprehensive gain, net of tax: — — 1,526 — 1,526Comprehensive income 27,015 36,214 20,906 (55,430) 28,705Comprehensive (income) loss attributable to noncontrollinginterest — — 198 — 198Comprehensive income (loss) attributable to controllinginterest $ 27,015 $ 36,214 $ 21,104 $ (55,430) $ 28,903

PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)(Unaudited)

Year Ended December 31, 2012 Parent Guarantor Non-Guarantor Eliminations ConsolidatedComprehensive income: Net income $ 37,313 $ 54,961 $ 32,816 $ (87,992) $ 37,098Other comprehensive gain, net of tax:

Currency translation difference on related borrowings — — — — —Currency translation difference on foreign currency netinvestments — — — — —

Total other comprehensive gain, net of tax: — — — — —Comprehensive income 37,313 54,961 32,816 (87,992) 37,098Comprehensive (income) loss attributable to noncontrollinginterest — — 215 — 215Comprehensive income (loss) attributable to controllinginterest $ 37,313 $ 54,961 $ 33,031 $ (87,992) $ 37,313

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATING CONDENSED STATEMENT OF COMPREHENSIVE INCOME (LOSS)

(Dollars in Thousands)(Unaudited)

Year ended December 31, 2011 Parent Guarantor Non-Guarantor Eliminations ConsolidatedComprehensive income: Net income $(50,451) $ (49,106) $ 25,428 $ 23,484 $ (50,645)Other comprehensive gain, net of tax:

Currency translation difference on related borrowings — — — — —Currency translation difference on foreign currency netinvestments — — — — —

Total other comprehensive gain, net of tax: — — — — —Comprehensive income (50,451) (49,106) 25,428 23,484 (50,645)Comprehensive (income) loss attributable tononcontrolling interest — — 194 — 194Comprehensive income (loss) attributable to controllinginterest $(50,451) $ (49,106) $ 25,622 $ 23,484 $ (50,451)

PARKER DRILLING COMPANY AND SUBSIDIARIES

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CONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS(Dollars in Thousands)

(Unaudited)

Year Ended December 31, 2013

Parent Guarantor Non-Guarantor Eliminations ConsolidatedCash flows from operating activities: Net income (loss) $ 27,015 $ 36,214 $ 19,380 $ (55,430) $ 27,179Adjustments to reconcile net income(loss) to net cash provided by operatingactivities:

Depreciation and amortization — 77,416 56,637 — 134,053Loss on extinguishment of debt 5,218 — — — 5,218Gain on disposition of assets — (1,759) (2,235) — (3,994)Deferred income tax expense (3,137) 19,454 (3,618) — 12,699Provision for reduction in carryingvalue of certain assets — — 2,544 — 2,544Expenses not requiring cash 13,173 12 4,579 — 17,764Equity in net earnings of subsidiaries (55,430) — — 55,430 —Change in accounts receivable (7) (12,888) (20,617) — (33,512)Change in other assets 74,411 (85,520) 487 — (10,622)Change in accrued income taxes 6,617 (1,052) 4,889 — 10,454Change in liabilities 6,934 (877) (6,343) — (286)

Net cash provided by (used in) operatingactivities 74,794 31,000 55,703 — 161,497Cash flows from investing activities: Capital expenditures — (94,269) (61,376) — (155,645)Proceeds from the sale of assets — 3,725 4,493 — 8,218Acquisition of ITS, net of cash acquired — (6,903) (111,088) — (117,991)Intercompany dividend payment — — — — —Net cash (used in) investing activities — (97,447) (167,971) — (265,418)Cash flows from financing activities:

Proceeds from debt issuance 350,000 — — — 350,000Proceeds from draw on revolvercredit facility

— — — — —Repayment of long term debt (125,000) — — — (125,000)Repayment of term loan (50,000) — — — (50,000)Paydown on revolver credit facility — — — — —Payment of debt issuance costs (11,172) — — — (11,172)Payment of debt extinguishmentcosts — — — — —Excess tax benefit from stock-basedcompensation 896 — — — 896Intercompany advances, net (193,072) 63,734 129,338 — —

Net cash provided by (used in) financingactivities (28,348) 63,734 129,338 — 164,724Net change in cash and cash equivalents 46,446 (2,713) 17,070 — 60,803Cash and cash equivalents at beginning ofyear 42,251 11,023 34,612 — 87,886Cash and cash equivalents at end of year $ 88,697 $ 8,310 $ 51,682 $ — $ 148,689

See accompanying notes to unaudited consolidated condensed financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)(Unaudited)

Year Ended December 31, 2012

Parent Guarantor Non-Guarantor Eliminations ConsolidatedCash flows from operating activities: Net income (loss) $ 37,313 $ 54,961 $ 32,816 $ (87,992) $ 37,098Adjustments to reconcile net income(loss)to net cash provided by operatingactivities:

Depreciation and amortization — 65,354 47,663 — 113,017Loss on extinguishment of debt 2,130 — — — 2,130Gain on disposition of assets — (775) (1,199) — (1,974)Deferred income tax expense 2,257 15,429 (1,849) — 15,837Expenses not requiring cash 16,558 33,644 (27,602) — 22,600Equity in net earnings of subsidiaries (43,884) — — 43,884 —Change in accounts receivable (445) (1,788) 17,474 — 15,241Change in other assets 1,649 2,060 (9,200) — (5,491)Change in accrued income taxes (4,055) 220 (2,267) — (6,102)Change in liabilities 3,914 (4,158) (2,413) — (2,657)

Net cash provided by (used in) operatingactivities 15,437 164,947 53,423 (44,108) 189,699Cash flows from investing activities: Capital expenditures — (176,333) (15,210) — (191,543)Proceeds from the sale of assets — 2,062 1,875 — 3,937Intercompany dividend payment (8,387) (4,357) (31,364) 44,108 —Net cash provided by (used in) investingactivities (8,387) (178,628) (44,699) 44,108 (187,606)Cash flows from financing activities:

Proceeds from debt issuance 130,000 — — — 130,000Proceeds from draw on revolvercredit facility 7,000 — — — 7,000Paydown on senior notes (125,000) — — — (125,000)Paydown on term note

(18,000) — — — (18,000)Paydown on revolver credit facility — — — — —Payment of debt issuance costs (4,859) — — — (4,859)Payment of debt extinguishmentcosts (555) — — — (555)Excess tax benefit from stock-basedcompensation (662) — — — (662)Intercompany advances, net (8,393) 20,492 (12,099) — —

Net cash provided by (used in) financingactivities (20,469) 20,492 (12,099) — (12,076)Net change in cash and cash equivalents (13,419) 6,811 (3,375) — (9,983)Cash and cash equivalents at beginning ofyear 55,670 4,212 37,987 — 97,869Cash and cash equivalents at end of year $ 42,251 $ 11,023 $ 34,612 $ — $ 87,886

See accompanying notes to unaudited consolidated condensed financial statements.

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PARKER DRILLING COMPANY AND SUBSIDIARIESCONSOLIDATED CONDENSED STATEMENTS OF CASH FLOWS

(Dollars in Thousands)(Unaudited)

Year Ended December 31, 2011

Parent Guarantor Non-Guarantor Eliminations ConsolidatedCash flows from operating activities: Net income (loss) $ (50,451) $ (49,106) $ 25,428 $ 23,484 $ (50,645)Adjustments to reconcile net income (loss)to netcash provided by operating activities:

Depreciation and amortization — 62,744 49,392 — 112,136Loss on extinguishment of debt — — — — —Gain on disposition of assets — (2,706) (953) — (3,659)Deferred income tax expense 31,518 (57,030) (22,863) — (48,375)Impairment and other charges — 170,000 — — 170,000Provision for reduction in carrying value ofcertain assets — 1,350 — — 1,350Expenses not requiring cash 16,411 376 (3,954) — 12,833Equity in net earnings of subsidiaries 23,484 — — (23,484) —Change in accounts receivable (288,333) 347,344 (65,852) — (6,841)Change in other assets 62,173 (16,724) 16,404 — 61,853Change in accrued income taxes (12,852) (2,053) 17,046 — 2,141Change in liabilities 2,398 (51,351) 24,045 — (24,908)

Net cash provided by (used in) operating activities (215,652) 402,844 38,693 — 225,885Cash flows from investing activities: Capital expenditures — (174,999) (15,400) — (190,399)Proceeds from the sale of assets — 4,335 1,200 — 5,535Proceeds from insurance settlements — 250 — — 250Intercompany dividend payment — — — — —Net cash provided by (used in) investing activities — (170,414) (14,200) — (184,614)Cash flows from financing activities:

Proceeds from debt issuance 50,000 — — — 50,000Paydown on term note (21,000) — — — (21,000)Paydown on revolver credit facility (25,000) — — — (25,000)Payment of debt issuance costs (504) — — — (504)Payment of debt extinguishment costs — — — — —Proceeds from stock options exercised 183 — — — 183Excess tax benefit from stock-basedcompensation 1,488 — — — 1,488Intercompany advances, net 252,320 (230,535) (21,785) — —

Net cash provided by (used in) financing activities 257,487 (230,535) (21,785) — 5,167Net change in cash and cash equivalents 41,835 1,895 2,708 — 46,438Cash and cash equivalents at beginning of year 13,835 2,317 35,279 — 51,431Cash and cash equivalents at end of year $ 55,670 $ 4,212 $ 37,987 $ — $ 97,869

See accompanying notes to unaudited consolidated condensed financial statements.

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Note 19 — Selected Quarterly Financial Data

Quarter

Year 2013 First Second Third Fourth Total (Dollars in Thousands Except Per Share Amounts) (Unaudited)Revenues $ 167,135 $ 225,954 $ 237,762 $ 243,321 $ 874,172Operating gross margin(2) $ 20,877 $ 50,273 $ 48,733 $ 48,564 $ 168,447Operating income $ 9,180 $ 28,587 $ 35,589 $ 28,516 $ 101,872Net income attributable to controlling interest $ 592 $ 8,281 $ 7,970 $ 10,172 $ 27,015Basic earnings per share — net income(1) $ 0.00 $ 0.07 $ 0.07 $ 0.08 $ 0.23Diluted earnings per share — net income(1) $ 0.00 $ 0.07 $ 0.07 $ 0.08 $ 0.22 Quarter

Year 2012 First Second Third Fourth Total (Dollars in Thousands Except Per Share Amounts) (Unaudited)Revenues $ 176,495 $ 178,895 $ 165,200 $ 157,171 $ 677,761Operating gross margin(2) $ 53,744 $ 46,914 $ 34,261 $ 16,637 $ 151,556Operating income $ 48,689 $ 40,978 $ 25,903 $ (8,297) $ 107,273Net income (loss) attributable to controllinginterest $ 26,392 $ 20,083 $ 10,936 $ (20,098) $ 37,313Basic earnings per share — net income (loss)(1) $ 0.23 $ 0.17 $ 0.09 $ (0.17) $ 0.32Diluted earnings per share — net income(loss)(1) $ 0.22 $ 0.17 $ 0.09 $ (0.17) $ 0.31

1) As a result of shares issued during the year, earnings per share for each of the year’s four quarters, which are based on weightedaverage shares outstanding during each quarter, may not equal the annual earnings per share, which is based on the weighted averageshares outstanding during the year. Additionally, as a result of rounding to the thousands, revenues, operating gross margin, operatingincome, and net income (loss) attributable to controlling interest may not equal the 2013 year to date results.

2) As the Company modified its reporting segments to be consistent with recent organizational changes to improve our drillingorganization, expenses related to our U.S. Barge Drilling segment were found to be incorrectly included in our general andadministrative expense during the first through third quarters of the current year. These expenses have been appropriately reclassifiedto be included as part of the segment operating expenses, therefore our operating gross margin for each of the first three quarters willnot agree to the respective 10-Q reports for the current year only.

Note 20 — Recent Accounting PronouncementsFair value measurements — Effective January 1, 2012, we adopted the accounting standards update that changes the wording used to

describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements.Some of the amendments included in this update are intended to clarify the applications of existing fair value measurement requirements.The update is effective for annual periods beginning after December 15, 2011. This adoption did not have a material effect on thedisclosures contained in our notes to the consolidated financial statements.

Comprehensive Income — On January 1, 2012, we adopted an update issued by the FASB to existing guidance on the presentation ofcomprehensive income. The update eliminates the option to present the components of other comprehensive income (OCI) as part of thestatement of changes in stockholders’ equity. Public entities are required to comply with the new reporting requirements for fiscal yearsbeginning after December 15, 2011 and interim periods within those years. Calendar year-end companies must adopt the requirements forthe quarter ended March 31, 2012. The adoption of this update did not have a material impact on our financial position, results ofoperations, cash flows, or disclosures.

Impairment — In July 2012, the FASB issued an update to existing guidance on the impairment assessment of indefinite-livedintangibles. This update simplifies the impairment assessment of indefinite-lived intangibles by allowing companies to consider qualitativefactors to determine whether it is more likely than not that the fair value of an indefinite-lived intangible

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asset is less than its carrying amount before performing the two step impairment review process. The adoption of this update did not havean impact on our condensed consolidated financial statements.

Note 21 — Subsequent Events

6.75% Senior Notes, due July 2022On January 22, 2014, we issued $360.0 million aggregate principal amount of 6.75% Notes pursuant to an Indenture between the

Company and The Bank of New York Mellon Trust Company, N.A., as trustee. Net proceeds from the 6.75% Notes offering plus a $40.0million Term Loan on the Secured Credit Agreement and cash on hand, were utilized to redeem $416.2 million aggregate principal amountof our outstanding 9.125% Notes due 2018 pursuant to a tender and consent solicitation offer commenced on January 7, 2014. The tenderoffer price was $1,061.98, inclusive of a $30.00 consent payment, for each $1,000.00 principal amount of 9.125% Notes, plus accrued andunpaid interest. On January 22, 2014, we paid $453.7 million for the tendered bonds, comprised of $416.2 million of aggregate principalamount of the bonds, $25.8 million of tender and consent premiums and $11.7 million of accrued interest. After payment for the tenderednotes, $8.8 million aggregate principal amount of our 9.125% Notes remains outstanding.

The 6.75% Notes are general unsecured obligations of the Company and rank equal in right of payment with all of our existing andfuture senior unsecured indebtedness. The 6.75% Notes are jointly and severally guaranteed by all of our subsidiaries that guaranteeindebtedness under our Secured Credit Agreement. Interest on the 6.75% Notes is payable on January 15 and July 15 of each year,beginning July 15, 2014. Debt issuance costs related to the 6.75% Notes are estimated to be $7.1 million and will be amortized over theterm of the notes using the effective interest rate method. The Term Loan amortizes quarterly with required payments of $2.5 million. Forfurther discussion of the Term Loan see Note 8 - Long-Term Debt.

At any time prior to January 15, 2017, we may redeem up to 35 percent of the aggregate principal amount of the 6.75% Notes at aredemption price of 106.75 percent of the principal amount, plus accrued and unpaid interest to the redemption date, with the net cashproceeds of certain equity offerings by us. On and after January 15, 2018, we may redeem all or a part of the 6.75% Notes upon appropriatenotice, at a redemption price of 103.375 percent of the principal amount, and at redemption prices decreasing each year thereafter to parbeginning January 15, 2020. If we experience certain changes in control, we must offer to repurchase the 6.75% Notes at 101.0 percent ofthe aggregate principal amount, plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

The Indenture restricts our ability and the ability of certain subsidiaries to: (i) sell assets, (ii) pay dividends or make otherdistributions on capital stock or redeem or repurchase capital stock or subordinated indebtedness, (iii) make investments, (iv) incur orguarantee additional indebtedness; (v) create or incur liens; (vi) enter into sale and leaseback transactions; (vii) incur dividend or otherpayment restrictions affecting subsidiaries, (viii) merge or consolidate with other entities, (ix) enter into transactions with affiliates, and (x)engage in certain business activities. Additionally, the Indenture contains certain restrictive covenants designating certain events as Eventsof Default. These covenants are subject to a number of important exceptions and qualifications.

9.125% Senior Notes, due April 2018On January 7, 2014, we commenced a tender and consent solicitation with respect to the 9.125% Notes issued pursuant to an

Indenture between the Company and The Bank of New York Mellon Trust Company, N.A., as trustee.. The tender offer price was$1,061.98, inclusive of a $30.00 consent payment, for each $1,000 principal amount of 9.125% Notes, plus accrued and unpaid interest. OnJanuary 22, 2014, we paid $453.7 million for the tendered 9.125% Notes, comprised of $416.2 million of aggregate principal amount of the9.125% Notes, $25.8 million of tender and consent premiums and $11.7 million of accrued interest. After payment for the tendered 9.125%Notes, $8.8 million aggregate principal amount of our 9.125% Notes remains outstanding.

At any time prior to April 1, 2014, we may redeem all or a part of the 9.125% Notes upon appropriate notice, at a redemption price of104.563 percent of the principal amount, and at redemption prices decreasing each year thereafter to par beginning April 1, 2016. If weexperience certain changes in control, we must offer to repurchase the 9.125% Notes at 101.0 percent of the aggregate principal amount,plus accrued and unpaid interest and additional interest, if any, to the date of repurchase.

On January 24, 2014, the Indenture was amended to remove most of the restrictions on our ability and the ability of certainsubsidiaries to: (i) sell assets, (ii) pay dividends or make other distributions on capital stock or redeem or repurchase capital stock orsubordinated indebtedness, (iii) make investments, (iv) incur or guarantee additional indebtedness; (v) create or incur liens; (vi) enter intosale and leaseback transactions; (vii) incur dividend or other payment restrictions affecting subsidiaries, (viii) merge or consolidate withother entities, (ix) enter into transactions with affiliates, and (x) engage in certain business activities. The Indenture also was amended toremove certain restrictive covenants designating certain events as Events of Default. Additionally, the remaining restrictive covenants aresubject to a number of important exceptions and qualifications.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIALDISCLOSURE

NoneITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures — In accordance with the Securities Exchange Act of 1934 Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officerand Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by thisreport. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls andprocedures, as defined in the Exchange Act Rules 13a-15 and 15d-15, were effective, as of December 31, 2013, to provide reasonableassurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is (1) accumulated andcommunicated to our management, including our Chief Executive Officer and our Chief Financial Officer, to allow timely decisionsregarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the Securities andExchange Commission’s rules and forms.

Management’s Report on Internal Control over Financial Reporting — The Company’s management is responsible for establishingand maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f).Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting andthe preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the UnitedStates. Our internal control over financial reporting includes those policies and procedures that:

• pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions ofthe assets of the Company;

• provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements inaccordance with accounting principles generally accepted in the United States, and that receipts and expenditures of the Companyare being made only in accordance with authorization of management and directors of the Company; and

• provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of theCompany’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projectionsof any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes inconditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Company’s management with the participation of the chief executive officer and chief financial officer assessed the effectivenessof our internal control over financial reporting as of December 31, 2013 based on criteria established in Internal Control — IntegratedFramework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Management’s assessmentincluded evaluation of the design and testing of the operational effectiveness of our internal control over financial reporting. Managementreviewed the results of its assessment with the audit committee of the board of directors.

Based on that assessment and those criteria, management has concluded that our internal control over financial reporting was effectiveas of December 31, 2013.

KPMG LLP, our independent registered public accounting firm that audited the consolidated financial statements included in thisAnnual Report Form 10-K, has issued a report with respect to our internal control over financial reporting as of December 31, 2013.

Changes in Internal Control Over Financial Reporting — The SEC's rules permit the exclusion of an assessment of theeffectiveness of a registrant's disclosure controls and procedures as they relate to its internal controls over financial reporting for anacquired business during the first year following such acquisition, if among other circumstances and factors there is not adequate timebetween the acquisition date and the date of assessment. As previously noted in this Form 10-K, we completed the ITS Acquisition, onApril 22, 2013. ITS represents approximately 11.0 percent of our total assets as of December 31, 2013 and approximately 10.0 percent and37.0 percent of revenues and net income, respectively, for the year ended December 31, 2013. The ITS Acquisition had a material impacton internal control over financial reporting. Management's assessment and conclusion on the effectiveness of the Company's disclosurecontrols and procedures as of December 31, 2013 excluded an assessment of the internal control over financial reporting of ITS. We arenow in the process of integrating ITS' operations including internal controls and processes. We are in the process of extending to ITS ourSection 404 compliance program under the Sarbanes-Oxley Act of 2002 and the applicable rules and regulations under such Act. Other thanchanges resulting from the ITS Acquisition discussed above, there have been no changes in our internal control over financial reporting

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(as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during our most recent fiscal quarter that has materially affected, or isreasonably likely to materially affect, our internal control over financial reporting.

ITEM 9B. OTHERINFORMATION

None.

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PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATEGOVERNANCE

Information with respect to directors can be found under the captions “Item 1 — Election of Directors” and “Board of Directors” inour 2014 Proxy Statement for the Annual Meeting of Stockholders to be held on May 1, 2014. Such information is incorporated herein byreference.

Information with respect to executive officers is shown in Item 1 of this Annual Report on Form 10-K.Information with respect to our audit committee and audit committee financial expert can be found under the caption “The Audit

Committee” of our 2014 Proxy Statement for the Annual Meeting of Stockholders to be held on May 1, 2014 and is incorporated herein byreference.

The information in our 2014 Proxy Statement for the Annual Meeting of Stockholders to be held on May 1, 2014 set forth under thecaption “Section 16(a) Beneficial Ownership Reporting Compliance” is incorporated herein by reference.

We have adopted the Parker Drilling Code of Corporate Conduct (CCC) which includes a code of ethics that is applicable to the chiefexecutive officer, chief financial officer, controller and other senior financial personnel as required by the SEC. The CCC includesprovisions that will ensure compliance with the code of ethics required by the SEC and with the minimum requirements under the corporategovernance listing standards of the NYSE. The CCC is publicly available on our website at http://www.parkerdrilling.com. If any waiversof the CCC occur that apply to a director, the chief executive officer, the chief financial officer, the controller or senior financial personnelor if the Company materially amends the CCC, we will disclose the nature of the waiver or amendment on the website and in a currentreport on Form 8-K within four business days.

ITEM 11. EXECUTIVECOMPENSATION

The information under the captions “Executive Compensation,” “Fees and Benefit Plans for Non-Employee Directors,”“2013 Director Compensation Table,” and “Compensation Committee Report” in our 2014 Proxy Statement for the Annual Meeting ofStockholders to be held on May 1, 2014 is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS, MANAGEMENT AND RELATEDSTOCKHOLDER MATTERS

The information required by this item is hereby incorporated by reference to the information appearing under the captions “SecurityOwnership of Officers, Directors and Principal Stockholders” and “Equity Compensation Plan Information” in our 2014 Proxy Statementfor the Annual Meeting of Stockholders to be held on May 1, 2014.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTORINDEPENDENCE

The information required by this item is hereby incorporated by reference to such information appearing under the captions “CertainRelationships and Related Party Transactions” and “Director Independence Determination” in our 2014 Proxy Statement for the AnnualMeeting of Stockholders to be held on May 1, 2014.

ITEM 14. PRINCIPAL ACCOUNTING FEES ANDSERVICES

The information required by this item is hereby incorporated by reference to the information appearing under the captions “Audit andNon-Audit Fees” and “Policy on Audit Committee Pre-Approval of Audit and Permissible Non-Audit Services of Independent RegisteredPublic Accounting Firm” in our 2014 Proxy Statement for the Annual Meeting of the Stockholders to be held on May 1, 2014.

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PART IVITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) The following documents are filed as part of this report:(1) Financial Statements of Parker Drilling Company and subsidiaries which are included in Part II, Item 8:

PageReport of Independent Registered Public Accounting Firm 43Consolidated Statement of Operations for the years ended December 31, 2013, 2012 and 2011 44Consolidated Statement of Comprehensive Income for the years ended December 31, 2013, 2012 and 2011 45Consolidated Balance Sheet as of December 31, 2013 and 2012 46Consolidated Statement of Cash Flows for the years ended December 31, 2013, 2012 and 2011 47Consolidated Statement of Stockholders’ Equity for the years ended December 31, 2013, 2012 and 2011 48Notes to the Consolidated Financial Statements 49

(2) Financial Statement Schedule: Schedule II — Valuation and qualifying accounts

93(3) Exhibits:

ExhibitNumber Description

2.1

—

Sale and Purchase Agreement, dated April 22, 2013, among ITS Tubular Services (Holdings) Limited, as Seller, IanDavid Green, John Bruce Cartwright and Graham Douglas Frost, as joint administrators of the Seller, ITS Holdings,Inc. and PD International Holdings C.V., Parker Drilling Offshore Corporation and Parker Drilling Company(Incorporated by reference to Exhibit 10.1 to Parker Drilling Company's Current Report on Form 8-K filed on April 23,2013).

3.1

—

Restated Certificate of Incorporation of the Company, as amended on May 16, 2007 (incorporated by reference toExhibit 3.1 to the Company’s Quarterly Report on Form 10-Q filed on November 9, 2007).

3.2

—

Parker Drilling Company By-Laws, effective as amended March 11, 2011 (incorporated by reference to Exhibit 3.2 tothe Company’s Current Report on Form 8-K filed on March 16, 2011).

4.1

—

Indenture, dated March 22, 2010, among Parker Drilling Company, the guarantors named therein and The Bank of NewYork Mellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.1 to the Company’s CurrentReport on Form 8-K filed on March 22, 2010).

4.2

—

First Supplemental Indenture, dated June 21, 2013, among Parker Drilling Company, as Guarantor and The Bank ofNew York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 10.2 to the Company'sQuarterly Report on Form 10-Q filed August 7, 2013).

4.3

—

Second Supplemental Indenture, dated January 24, 2014, among Parker Drilling Company, the guarantors namedtherein and The Bank of New York Mellon Trust Company, N.A., as Trustee (incorporated by reference to Exhibit 4.1to the Company's Current Report on Form 8-K filed on January 28, 2014).

4.4

—

Form of 9 1 / 8 % Senior Note due 2018 (incorporated by reference to Exhibit 4.2 to the Company’s Current Report onForm 8-K filed on March 22, 2010).

4.5

—

Indenture, dated July 30, 2013, between Parker Drilling Company, the subsidiary guarantors from time to time partieshereto, as, collectively, Guarantors, and The Bank of New York Mellon Trust Company, N.A. as Trustee (Incorporatedby reference to Exhibit 10.3 to Parker Drilling Company's Current Report on Form 8-K filed on July 25, 2013).

4.6

—

Form of 7.500% Senior Note due 2020 (incorporated by reference to Exhibit 4.2 to the Company's Current Report onForm 8-K filed on July 31, 2013).

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4.7

—

Indenture, dated January 22, 2014, among Parker Drilling Company, the Guarantors and The Bank of New YorkMellon Trust Company, N.A., as trustee (incorporated by reference to Exhibit 4.2 to the Company's Current Report onForm 8-K file on January 28, 2014).

4.8

—

Form of 6.750% Senior Note due 2018 (incorporated by reference to Exhibit 4.3 to the Company's Current Report onForm 8-K filed on January 28, 2014).

4.9

—

Registration Rights Agreement, dated July 30, 2013, by and among Parker Drilling Company, the guarantors namedtherein, Goldman, Sachs & Co., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities, LLC andRBS Securities Inc. (incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed onJuly 31, 2013).

4.10

—

Registration Rights Agreement, dated January 22, 2014, by and among Parker Drilling Company, the guarantors namedtherein, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Wells Fargo Securities, LLC, Barclays Capital Inc.,Deutsche Bank Securities Inc. and Goldman, Sachs & Co. (incorporated by reference to Exhibit 10.1 to the Company’sCurrent Report on Form 8-K filed on January 28, 2014).

10.1

—

Amended and Restated Credit Agreement dated as of December 14, 2012, among Parker Drilling Company, asBorrower, Bank of America, N.A., as Administrative Agent and L/C Issuer, the several banks and other financialinstitutions or entities from time to time parties thereto, NATIXIS, New York Branch, Wells Fargo Bank, N.A., andWhitney Bank as Co-Documentation Agents, and Merrill Lynch, Fenner & Smith Incorporated as Sole Lead Arrangerand Book Manager

10.2

—

First Amendment to Term Loan Agreement dated July 19, 2013, among Parker Drilling Company, the lenders partythereto, Goldman Sachs Bank USA and certain other parties thereto (Incorporated by reference to Exhibit 10.5 to ParkerDrilling Company's Current Report on Form 8-K filed on July 22, 2013).

10.3

—

First Amendment to Amended and Restated Credit Agreement, dated as of July 19, 2013, among Parker DrillingCompany, as Borrower, certain Subsidiaries of the Borrower, as Guarantors, the Lenders party thereto, and Bank ofAmerica N.A., as administrative agent (Incorporated by reference to Exhibit 10.2 to Parker Drilling Company's CurrentReport on Form 8-K filed on July 22, 2013).

10.4

—

Parker Drilling Company Incentive Compensation Plan, dated December 17, 2008, and as amended and restatedeffective January 1, 2008 (incorporated by reference to Exhibit 10(b) to the Company’s Annual Report on Form 10-Kfiled on March 2, 2009).*

10.5

—

Parker Drilling Company Incentive Compensation Plan (as amended and restated effective January 1, 2009)(incorporated by reference to Exhibit 10.4 to the Company’s Annual Report on Form 10-K filed on March 1, 2011)*

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ExhibitNumber Description

10.6

—

Parker Drilling Company 2010 Long-Term Incentive Plan (incorporated by reference to Annex A to the Company’sDefinitive Proxy Statement filed on March 16, 2010).*

10.7

—

Form of Parker Drilling Company Restricted Stock Unit Incentive Agreement under the 2010 LTIP (incorporated byreference to Exhibit 10.18 to the Company’s Annual Report on Form 10-K filed on March 1, 2011).*

10.8

—

Form of Parker Drilling Company Performance Unit Award Incentive Agreement under the 2010 LTIP (incorporatedby reference to Exhibit 10.19 to the Company’s Annual Report on Form 10-K filed on March 1, 2011).*

10.9

—

Form of Indemnification Agreement entered into between Parker Drilling Company and each director and executiveofficer of Parker Drilling Company (incorporated by reference to Exhibit 10(g) to the Company’s Annual Report onForm 10-K filed on March 20, 2003).*

10.10

—

Employment Agreement between Mr. Robert L. Parker, Jr. and Parker Drilling Company, effective March 21, 2011(incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 25, 2011).*

10.11

—

First Amendment dated August 29, 2011 to First Amended and Restated Employment Agreement between Mr. RobertL. Parker Jr. and Parker Drilling Company, effective March 21, 2011 (incorporated by reference to Exhibit 10.1 to theCompany’s Current Report on Form 8-K filed on August 30, 2011).*

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ExhibitNumber Description

10.12

—

Employment Agreement, dated as of September 17, 2012, by and between Parker Drilling Company and Gary Rich(incorporated by reference to Exhibit 10.23 to the Company’s Current Report on Form 8-K filed on September 24,2012).*

10.13

—

Form of Restricted Stock Unit Incentive Agreement between Parker Drilling Company and Gary Rich (incorporated byreference to Exhibit 10.23 to the Company’s Current Report on Form 8-K filed on September 24, 2012).*

10.14

—

Employment Agreement between Mr. Jon-Al Duplantier and Parker Drilling Company, effective March 21, 2011(incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 25, 2011).*

10.15

—

First Amendment dated August 29, 2011 to Employment Agreement between Mr. Jon-Al Duplantier and Parker DrillingCompany, effective March 21, 2011 (incorporated by reference to Exhibit 10.4 to the Company’s Current Report onForm 8-K filed on August 30, 2011).*

10.16

—

Termination of Split Dollar Life Insurance Agreement between Parker Drilling Company, Robert L. Parker Sr., andRobert L. Parker Sr. and Catherine M. Parker Family Trust dated April 12, 2006 (incorporated by reference toExhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 12, 2006).*

10.17

—

Retirement and Separation Agreement, dated November 1, 2013, between Parker Drilling Company and Robert L.Parker, Jr. (Incorporated by reference to Exhibit 10.1 to Parker Drilling Company's Current Report on Form 8-K filedon November 4, 2013).

10.18

—

Employment Agreement dated May 3, 2013 between Parker Drilling Company and Christopher Weber (Incorporated byreference to Exhibit 10.1 to Parker Drilling Company's Current Report on Form 8-K filed on May 14, 2013).

10.19

—

Form of Restricted Stock Unit Incentive Agreement between Parker Drilling Company and Christopher Weber(Incorporated by reference to Exhibit 10.2 to Parker Drilling Company's Current Report on Form 8-K filed on May 14,2013).

21 — Subsidiaries of the Registrant. 23.1 — Consent of KPMG LLP — Independent Registered Public Accounting Firm. 31.1 — Gary Rich, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification. 31.2 — Christopher T. Weber, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a) Certification. 32.1 — Gary Rich, President and Chief Executive Officer, Section 1350 Certification. 32.2 — Christopher T. Weber, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

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ExhibitNumber Description

101.INS — XBRL Instance Document. 101.SCH — XBRL Taxonomy Schema Document. 101.CAL — XBRL Calculation Linkbase Document. 101.LAB — XBRL Label Linkbase Document. 101.PRE — XBRL Presentation Linkbase Document. 101.DEF — XBRL Definition Linkbase Document.____________________________

* — Management contract, compensatory plan or agreement.

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PARKER DRILLING COMPANY AND SUBSIDIARIESSCHEDULE II—VALUATION AND QUALIFYING ACCOUNTS

(Dollars in Thousands)

Classifications

Balance atbeginning

of year

Chargedto cost

andexpenses

Chargedto otheraccounts Deductions

Balanceat end

ofyear

Year ended December 31, 2013 Allowance for doubtful accounts and notes $ 8,117 $ 5,092 $ 5,861 $ (6,217) $ 12,853Allowance for obsolete rig materials and supplies $ 312 — $ 3,586 $ (453) $ 3,445Deferred tax valuation allowance $ 4,805 $ 2,010 $ 12 $ — $ 6,827

Year ended December 31, 2012 Allowance for doubtful accounts and notes $ 1,544 $ 4,264 $ 3,195 $ (886) $ 8,117Allowance for obsolete rig materials and supplies $ 316 — $ — $ (4) $ 312Deferred tax valuation allowance $ 6,467 $ (1,662) $ — $ — $ 4,805

Year ended December 31, 2011 Allowance for doubtful accounts and notes $ 7,020 $ 2,258 $ (2,034) $ (5,700) $ 1,544Allowance for obsolete rig materials and supplies $ 309 $ 26 $ — $ (19) $ 316Deferred tax valuation allowance $ 5,532 $ 2,542 $ (1,607) $ — $ 6,467

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SIGNATURESPursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its

behalf by the undersigned hereunto duly authorized.

PARKER DRILLING COMPANY By: /s/ Christopher T. Weber Christopher T. Weber Senior Vice President and Chief Financial Officer

Date: March 10, 2014Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on

behalf of the Registrant and in the capacities and on the dates indicated.

Signature Title Date By: /s/ Gary G. Rich President, Chief Executive Officer, and Director (Principal

Executive Officer) March 10, 2014

Gary G. Rich By: /s/ Christopher T. Weber Senior Vice President and Chief Financial Officer (Principal

Financial Officer) March 10, 2014

Christopher T. Weber By: /s/ Philip A. Schlom Controller (Principal Accounting Officer) March 10, 2014 Philip A. Schlom By: /s/ Robert L. Parker Jr. Chairman and Director March 10, 2014 Robert L. Parker Jr. By: /s/ Jonathan M. Clarkson Director March 10, 2014 Jonathan M. Clarkson By: /s/ George J. Donnelly Director March 10, 2014 George J. Donnelly By:

/s/ Robert W. Goldman Director March 10, 2014

Robert W. Goldman By: /s/ Gary R. King Director March 10, 2014 Gary R. King By: /s/ Richard D. Paterson Director March 10, 2014 Richard D. Paterson By: /s/ Roger B. Plank Director March 10, 2014 Roger B. Plank By: /s/ R. Rudolph Reinfrank Director March 10, 2014 R. Rudolph Reinfrank By: /s/ Peter C. Wallace Director March 10, 2014 Peter C. Wallace

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Table of Contents

INDEX TO EXHIBITS

Exhibit Number Description21 — Subsidiaries of the Registrant.23.1 — Consent of KPMG LLP — Independent Registered Public Accounting Firm.31.1 — Gary G. Rich, President and Chief Executive Officer, Rule 13a-14(a)/15d-14(a) Certification.31.2

—

Christopher T. Weber, Senior Vice President and Chief Financial Officer, Rule 13a-14(a)/15d-14(a)Certification.

32.1 — Gary G. Rich, President and Chief Executive Officer, Section 1350 Certification.32.2 — Christopher T. Weber, Senior Vice President and Chief Financial Officer, Section 1350 Certification.

101.INS — XBRL Instance Document.101.SCH — XBRL Taxonomy Schema Document.101.CAL — XBRL Calculation Linkbase Document.101.LAB — XBRL Label Linkbase Document.101.PRE — XBRL Presentation Linkbase Document.101.DEF — XBRL Definition Linkbase Document.

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EXHIBIT 21SUBSIDIARIES OF THE REGISTRANT

Consolidated Subsidiaries of the Registrant Parker North America Operations, Inc. (Nevada) (2) 100 %Parker Drilling Arctic Operating, Inc. (Delaware) 100 %Parker Drilling International Holding Company, LLC (Delaware) (1) 100 %Parker Drilling Management Services, Inc. (Nevada) 100 % Certain subsidiaries have been omitted from the list since they would not, even if considered in the aggregate, constitute a significant subsidiary.All subsidiaries are included in the consolidated financial statements. (1) Parker Drilling International Holding Company owns 64.8% of Parker Drilling Eurasia, Inc. (2) Parker North America Operations, Inc. owns 100% of Parker Drilling Company North America, Inc. (Nevada); Parker USA Drilling Company(Nevada) and Parker Drilling Offshore Corporation (Nevada).*

* Parker Drilling Offshore Corporation owns 100% of the following entities:• Mallard Argentine Holdings, Ltd. (Cayman Islands)• Mallard Drilling of South America, Inc. (Cayman Islands)• Mallard Drilling of Venezuela, Inc. (Cayman Islands)• Parker Drilling Offshore International, Inc. (formerly Mallard Drilling International, Inc.)(Cayman Islands), which owns 100% of Parker

Drilling (Nigeria) Limited (Nigeria) and 100% of KDN Drilling Limited (Nigeria).• Parker Drilling Offshore USA, L.L.C. (Oklahoma), which owns 100% of Parker Drilling Company of Mexico, LLC (Nevada), 98% of

Parker Drilling de Mexico, SRL (Mexico), 2% of PD Servicios Integrales, SRL (Mexico) and 100% of Parker Enex, LLC (Delaware).• Parker Technology, L.L.C. (Louisiana)• Parker Tools, LLC (Oklahoma), which owns 99% of Quail Tools, L.P. (formerly Quail Tools, L.L.P.) (Oklahoma).• Quail USA, LLC (Oklahoma), which owns 1% of Quail Tools, L.P. (formerly Quail Tools, L.L.P.) (Oklahoma).• ITS Rental and Sales, Inc. (Texas)

* Parker Drilling Offshore Corporation owns 98% of PD Servicios Integrales, SRL (Mexico).* Parker Drilling Offshore Corporation owns 2% of Parker Drilling de Mexico, SRL (Mexico).* Parker Drilling Offshore Corporation owns 35.2% of Parker Drilling Eurasia, Inc. (Delaware), which owns 100% of Parker Drilling Company

International Limited (Nevada), 100% of Parker Drilling Company Eastern Hemisphere, Ltd. Co. (Oklahoma), 100% of Parker Drillserv, LLC(Delaware), 100% of Parker Drilltech, LLC (Delaware) and 99.96% of PD Offshore Holdings C.V. (Netherlands) which owns 100% of Parker3source, LLC (Delaware) and 99.97% of PD Selective Holdings C.V. (Netherlands) which owns 100% of the following entities:• Parker Drillex, LLC (Delaware)• Parker Drilling AME Limited (Cayman Islands)• Parker Drilling Company of New Guinea, LLC (Delaware)• Parker Drilling Company of Sakhalin (Russia)• Parker Drilling Company of Singapore, LLC (Delaware)• Parker Drilling Netherlands B.V. (Netherlands), which owns 100% of Parker Drilling International B.V. (Netherlands), 100 % of

Parker Drilling Kazakhstan B.V. (Netherlands), 100% of Parker Drilling Russia B.V. (Netherlands), 100% of Parker Drilling Overseas B.V.(Netherlands), 100% of Primorsky Drill Rig Services BV (Netherlands)

• Parker Drillsource, LLC (Delaware)• PD Labor Sourcing, Ltd. (Cayman Islands)• PD Personnel Services, Ltd. (Cayman Islands)• Parker Drilling Company Kuwait Limited (Bahamas).• Parker Singapore Rig Holding Pte. Ltd. (Singapore)

* Parker Drilling Offshore Corporation owns 26% of Parker Drilling Pacific Rim, Inc. (Delaware), which owns 100% of Parker Rigsource, LLC(Delaware) and 99.88% of PD International Holdings C.V. (Netherlands) which owns 99% of PD ITS Holdings C.V. (Netherlands), 100% of Parker 5272,LLC (Delaware) and 99.96% of PD Dutch Holdings C.V. (Netherlands) which owns 100% of the following entities:• Parker Drilling (Kazakstan), LLC (Delaware), which owns 100% of Parker Central Europe Rig Holdings LLC (Hungary) and 100% of AralParker CJSJ(Kazakhstan)• Parker Drilling Company International, LLC (Delaware), which owns 50% of Parker SMNG Drilling LLC (Russia)• Parker Drilling Company of New Zealand Limited (New Zealand)• Parker Drilling Dutch B.V. (Netherlands), which owns 100% of Parker Drilling Offshore B.V (Netherlands) and 50% of SaiPar Drilling Co

BV (Netherlands)

• Parker Drilling International of New Zealand Limited (New Zealand)* PD ITS Holdings C.V. (Netherlands) owns 99.97% of Servicios de Personal ITS S. De R.I. De C.V. (Mexico), 100% of ITS Energy Services (Cayman)

and 100% of International Tubular Services Limited (Scotland), which owns 66% of International Tubular Services-Egypt (I.T.S. Egypt) SAE (Egypt), 50%of Shenshen Weisheng ITS Tubular Equipment Co Ltd. (China), 70% of ITS Arabia Limited (Saudi Arabia) and 100% of the following entities:• ITS India Private Limited (India)• ITS Indonesia PTE Limited (Singapore)• International Tubulars FZE (Jebel Ali FZ, UAE), which owns 49% of International Tubular Services Middle East LLC (Abu Dhabi, UAE) and 100% of

Technology Specialist for Tubes Manufacturing & General Services LLC (Iraq)• ITS Energy Services Limited (Trinidad)• ITS Netherlands BV (Netherlands)• International Tubular Services De Mexico, S. De R.I. De C.v. (Mexico)• ITS Energy Services PTE Ltd (Singapore), which owns 100% of ITS Energy Services (Asia Pacific) PTE Ltd (Singapore) and ITS Energy Services

Sdn Bhd (Malaysia)

EXHIBIT 23.1Consent of Independent Registered Public Accounting Firm

The Board of Directors

Parker Drilling Company:

We consent to the incorporation by reference in the registration statement (No. 333-144111) on Form S-3, in the registration statement(No. 333‑193508) on Form S-4 and in the registration statements (Nos. 333-188754, 333-184230, 333-167695, 333-158130, 333-124697,333-59132, 333-57345, 333-41369, 333-84069, 333-99187) on Form S-8 of Parker Drilling Company of our report dated March 10, 2014,with respect to the consolidated balance sheets of Parker Drilling Company as of December 31, 2013 and 2012, and the relatedconsolidated statements of earnings, stockholders’ equity, and cash flows, and comprehensive income for each of the years in the three-year period ended December 31, 2013, and all related financial statement schedules, and the effectiveness of internal control over financialreporting as of December 31, 2013, which reports appears in the December 31, 2013 annual report on Form 10‑K of Parker DrillingCompany.

/s/ KPMG LLP

Houston, TX

March 10, 2014

EXHIBIT 31.1PARKER DRILLING COMPANY

RULE 13a-14(a)/15d-14(a) CERTIFICATIONI, Gary G. Rich, certify that:1. I have reviewed this annual report on Form 10-K for the period ended December 31, 2013, of Parker Drilling Company (the

registrant);2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary

to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect tothe period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in allmaterial respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in thisreport;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a-15(f) and 15d-15(f)) for the registrant and have:a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusionsabout the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based onsuch evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during theregistrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materiallyaffected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing theequivalent functions):a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting

which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financialinformation; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in theregistrant’s internal control over financial reporting.

Date: March 10, 2014

/s/ Gary G. RichGary G. RichPresident and Chief Executive Officer

EXHIBIT 31.2PARKER DRILLING COMPANY

RULE 13a-14(a)/15d-14(a) CERTIFICATIONI, Christopher T. Weber, certify that:1. I have reviewed this annual report on Form 10-K for the period ended December 31, 2013, of Parker Drilling Company (the

registrant);2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary

to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect tothe period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in allmaterial respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in thisreport;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange ActRules 13a-15(f) and 15d-15(f)) for the registrant and have:a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our

supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is madeknown to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designedunder our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation offinancial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusionsabout the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based onsuch evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during theregistrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materiallyaffected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financialreporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing theequivalent functions):a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting

which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financialinformation; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in theregistrant’s internal control over financial reporting.

Date: March 10, 2014

/s/ Christopher T. WeberChristopher T. WeberSenior Vice President and Chief Financial Officer

EXHIBIT 32.1CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350Pursuant to 18 U.S.C. Section 1350, the undersigned officer of Parker Drilling Company (the “Company) hereby certifies, to such officer’sknowledge, that:

1. The Company’s Annual Report on Form 10-K for the year ended December 31, 2013 (the “Report) fully complies with therequirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and result ofoperations of the Company.

Dated: March 10, 2014

/s/ Gary G. RichGary G. RichPresident and Chief Executive Officer

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as aseparate disclosure statement.

EXHIBIT 32.2CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350Pursuant to 18 U.S.C. Section 1350, the undersigned officer of Parker Drilling Company (the “Company) hereby certifies, to such officer’sknowledge, that:

1. The Company’s Annual Report on Form 10-K for the year ended December 31, 2013 (the “Report) fully complies with therequirements of section 13(a) or 15(d), as applicable, of the Securities Exchange Act of 1934; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and result ofoperations of the Company.

Dated: March 10, 2014

/s/ Christopher T. WeberChristopher T. WeberSenior Vice President and Chief Financial Officer

The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as aseparate disclosure statement.